Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITES EXCHANGE ACT OF 1934
For the period ended June 30, 2002
- OR -
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------
333-32170 PNM Resources, Inc. 85-0468296
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
1-6986 Public Service Company of New Mexico 85-0019030
(A New Mexico Corporation)
Alvarado Square
Albuquerque, New Mexico 87158
(505) 241-2700
Securities Registered Pursuant To Section 12(b) Of The Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
- ---------- ------------------- ---------------------
PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- -----
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Registrant Class Outstanding at August 1, 2002
- ---------- ----- -----------------------------
PNM Resources, Common Stock, No Par Value 39,117,799
Inc.
PNM RESOURCES, INC. AND SUBSIDIARIES
INDEX
Page No.
PART I. FINANCIAL INFORMATION:
Reports of Independent Public Accountants............................ 3
ITEM 1. FINANCIAL STATEMENTS
PNM Resources, Inc.
Consolidated Statements of Earnings
Three and Six Months Ended June 30, 2002 and 2001......... 7
Consolidated Balance Sheets
June 30, 2002 and December 31, 2001....................... 8
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2002 and 2001................... 10
Consolidated Statements of Comprehensive Income
Three and Six Months Ended June 30, 2002 and 2001......... 11
Public Service Company of New Mexico
Consolidated Statements of Earnings
Three and Six Months Ended June 30, 2002 and 2001......... 12
Consolidated Balance Sheets
June 30, 2002 and December 31, 2001....................... 13
Consolidated Statements of Cash Flows
Six Months Ended June 30, 2002 and 2001................... 15
Consolidated Statements of Comprehensive Income
Three and Six Months Ended June 30, 2002 and 2001......... 16
Notes to Consolidated Financial Statements........................ 17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS............ 31
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.............................................. 70
PART II. OTHER INFORMATION:
ITEM 1. LEGAL PROCEEDINGS........................................... 74
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 80
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 81
Signature ......................................................... 82
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of PNM Resources, Inc.
Albuquerque, New Mexico
We have reviewed the accompanying consolidated balance sheet of PNM Resources,
Inc. and subsidiaries (the Company) as of June 30, 2002, and the related
consolidated statements of earnings, cash flows and comprehensive income for the
three-month and six-month periods then ended. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements as of June 30, 2002, and for
the three- and six-month periods then ended for them to be in conformity with
accounting principles generally accepted in the United States of America.
The accompanying financial information as of December 31, 2001, and for the
three- and six-month periods ended June 30, 2001, were not audited or reviewed
by us and, accordingly, we do not express an opinion or any other form of
assurance on them.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
August 2, 2002
3
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Public Service Company of New Mexico
Albuquerque, New Mexico
We have reviewed the accompanying consolidated balance sheet of Public Service
Company of New Mexico (the Company) as of June 30, 2002, and the related
consolidated statements of earnings, cash flows and comprehensive income for the
three-month and six-month periods then ended. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States of America, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such consolidated financial statements as of June 30, 2002, and for
the three- and six-month periods then ended for them to be in conformity with
accounting principles generally accepted in the United States of America.
The accompanying financial information as of December 31, 2001, and for the
three- and six-month periods ended June 30, 2001, were not audited or reviewed
by us and, accordingly, we do not express an opinion or any other form of
assurance on them.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
August 2, 2002
4
This is a copy of a report previously issued by Arthur Andersen LLP. The report
has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP
provided an awareness letter for the inclusion of its report in this Quarterly
Report on Form 10-Q. The report was issued prior to the formation of PNM
Resources, Inc., the Holding Company of Public Service Company of New Mexico.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Public Service Company of New Mexico:
We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC
SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of
June 30, 2001, and the related condensed consolidated statements of earnings for
the three-month and six-month periods ended June 30, 2001 and 2000, and the
condensed consolidated statements of cash flows for the six-month periods ended
June 30, 2001 and 2000. These financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with auditing standards generally accepted in the United States, the objective
of which is the expression of an opinion regarding the financial statements
taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally
accepted in the United States, the consolidated balance sheet and statement of
capitalization of Public Service Company of New Mexico and subsidiaries as of
December 31, 2000, and the related consolidated statements of earnings, and cash
flows for the year then ended (not presented separately herein), and in our
report dated January 26, 2001, we expressed an unqualified opinion on those
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 2000 is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
August 13, 2001
5
This is a copy of a report previously issued by Arthur Andersen LLP. The report
has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP
provided a consent to the inclusion of its report in this Quarterly Report on
Form 10-Q.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
PNM Resources, Inc. and Public Service Company of New Mexico:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of PNM Resources, Inc. (a New Mexico Corporation) and
subsidiaries and Public Service Company of New Mexico and subsidiaries (a New
Mexico Corporation) as of December 31, 2001 and 2000, and the related
consolidated statements of earnings, cash flows and comprehensive income for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Companies' management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PNM Resources, Inc. and
subsidiaries and Public Service Company of New Mexico and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico
February 1, 2002
6
ITEM 1. FINANCIAL STATEMENTS
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Operating Revenues:
Electric................................... $220,516 $577,730 $424,479 $1,122,324
Gas........................................ 43,968 87,084 153,169 279,020
Unregulated businesses..................... 85 1,277 917 1,277
------------ ------------ ------------ ------------
Total operating revenues................. 264,569 666,091 578,565 1,402,621
------------ ------------ ------------ ------------
Operating Expenses:
Cost of energy sold........................ 122,692 433,841 277,800 930,939
Administrative and general................. 36,389 38,768 68,453 78,256
Energy production costs.................... 34,202 37,878 69,173 72,903
Depreciation and amortization.............. 25,217 23,929 49,996 48,148
Transmission and distribution costs........ 15,451 15,080 31,988 30,357
Taxes, other than income taxes............. 9,028 7,839 17,512 15,056
Income taxes............................... 2,141 28,209 11,507 69,115
------------ ------------ ------------ ------------
Total operating expenses................. 245,120 585,544 526,429 1,244,774
------------ ------------ ------------ ------------
Operating income......................... 19,449 80,547 52,136 157,847
------------ ------------ ------------ ------------
Other Income and Deductions:
Other income............................... 10,812 13,852 23,006 27,229
Other deductions........................... (983) (35,918) (947) (44,735)
Income tax (expense) benefit............... (3,432) 7,478 (8,274) 5,552
----------- ------------ ------------ ------------
Net other income and deductions.......... 6,397 (14,588) 13,785 (11,954)
------------ ------------ ------------ ------------
Income before interest charges........... 25,846 65,959 65,921 145,893
------------ ------------ ------------ ------------
Interest Charges............................. 14,689 16,362 29,815 32,744
------------ ------------ ------------ ------------
Net Earnings................................. 11,157 49,597 36,106 113,149
Preferred Stock Dividend Requirements........ 147 147 293 293
------------ ------------ ------------ ------------
Net Earnings Applicable to Common Stock...... $ 11,010 $ 49,450 $ 35,813 $ 112,856
============ ============ ============ ============
Net Earnings per Common Share:
Basic...................................... $ 0.28 $ 1.26 $ 0.92 $ 2.89
============ ============ ============ ============
Diluted.................................... $ 0.28 $ 1.24 $ 0.90 $ 2.84
============ ============ ============ ============
Dividends Paid per Share of Common Stock..... $ 0.22 $ 0.20 $ 0.42 $ 0.40
============ ============ ============ ============
The accompanying notes are an integral part of these financial statements.
7
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service..................................... $2,179,468 $2,118,417
Gas plant in service.......................................... 595,397 575,350
Common plant in service and plant held for future use......... 49,527 45,223
-------------- --------------
2,824,392 2,738,990
Less accumulated depreciation and amortization................ 1,272,484 1,234,629
-------------- --------------
1,551,908 1,504,361
Construction work in progress................................. 232,733 249,656
Nuclear fuel, net of accumulated amortization of
$16,455 and $16,954....................................... 26,586 26,940
-------------- --------------
Net utility plant........................................... 1,811,227 1,780,957
-------------- --------------
Other Property and Investments:
Other investments............................................. 430,370 552,453
Non-utility property, net of accumulated depreciation of
$1,665 and $1,580......................................... 1,613 1,784
-------------- --------------
Total other property and investments........................ 431,983 554,237
-------------- --------------
Current Assets:
Cash and cash equivalents..................................... 46,202 26,057
Accounts receivables, net of allowance for uncollectible
accounts of $17,075 and $18,025........................... 106,087 147,787
Other receivables............................................. 48,938 52,158
Inventories................................................... 36,702 36,483
Regulatory assets............................................. 100 10,473
Short-term investments........................................ 108,297 45,111
Other current assets.......................................... 27,525 31,428
-------------- --------------
Total current assets........................................ 373,851 349,497
-------------- --------------
Deferred Charges:
Regulatory assets............................................. 196,245 197,948
Prepaid retirement costs...................................... 39,176 18,273
Other deferred charges........................................ 87,367 33,726
-------------- --------------
Total deferred charges...................................... 322,788 249,947
-------------- --------------
$2,939,849 $2,934,638
============== ==============
The accompanying notes are an integral part of these financial statements.
8
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock...................................................... $ 622,468 $ 625,632
Accumulated other comprehensive loss, net of tax.................. (31,038) (28,996)
Retained earnings................................................. 442,596 415,388
-------------- --------------
Total common stockholders' equity.............................. 1,034,026 1,012,024
Minority interest.................................................... 12,056 11,652
Cumulative preferred stock without mandatory
redemption requirements......................................... 12,800 12,800
Long-term debt....................................................... 953,912 953,884
-------------- --------------
Total capitalization........................................... 2,012,794 1,990,360
-------------- --------------
Current Liabilities:
Short-term debt....................................................... 100,000 35,000
Accounts payable....................................................... 98,628 120,918
Accrued interest and taxes............................................. 54,452 72,022
Other current liabilities.............................................. 67,456 101,697
-------------- --------------
Total current liabilities...................................... 320,536 329,637
-------------- --------------
Deferred Credits:
Accumulated deferred income taxes...................................... 129,706 120,153
Accumulated deferred investment tax credits............................ 43,149 44,714
Regulatory liabilities................................................. 16,275 52,890
Regulatory liabilities related to accumulated deferred income tax...... 14,163 14,163
Accrued postretirement benefit costs................................... 15,154 14,929
Other deferred credits................................................. 388,072 367,792
-------------- --------------
Total deferred credits......................................... 606,519 614,641
-------------- --------------
$2,939,849 $2,934,638
============== ==============
The accompanying notes are an integral part of these financial statements.
9
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
----------------------------------
2002 2001
--------------- ---------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings........................................................ $ 36,106 $ 113,149
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization................................... 51,189 53,083
Other, net...................................................... (23,876) 29,117
Changes in certain assets and liabilities:
Accounts receivables.......................................... 41,700 (42,693)
Other assets.................................................. (9,684) 31,405
Accounts payable.............................................. (22,290) 1,081
Accrued taxes................................................. (17,278) 48,698
Other liabilities............................................. (45) 23,641
--------------- ---------------
Net cash flows provided by operating activities............... 55,822 257,481
--------------- ---------------
Cash Flows From Investing Activities:
Utility plant additions............................................. (127,781) (111,373)
Redemption of short-term investments................................ 45,000 -
Return of principal of PVNGS lessor notes........................... 8,996 8,535
Other............................................................... (6,452) (10,112)
--------------- ---------------
Net cash flows used for investing activities.................. (80,237) (112,950)
--------------- ---------------
Cash Flows From Financing Activities:
Borrowings.......................................................... 65,000 -
Exercise of employee stock options.................................. (3,312) (2,682)
Dividends paid...................................................... (16,723) (15,935)
Other............................................................... (405) (285)
--------------- ---------------
Net cash flows provided by (used for) financing activities.... 44,560 (18,902)
--------------- ---------------
Increase in Cash and Cash Equivalents................................. 20,145 125,629
Beginning of Period................................................... 26,057 107,691
--------------- ---------------
End of Period......................................................... $ 46,202 $233,320
=============== ===============
Supplemental Cash Flow Disclosures:
Interest paid....................................................... $ 28,914 $ 31,382
=============== ===============
Capitalized interest................................................ $ 3,995 $ -
=============== ===============
Income taxes paid, net ............................................. $ 41,784 $ 52,150
=============== ===============
The accompanying notes are an integral part of these financial statements.
10
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Net Earnings...................................... $ 11,157 $49,597 $ 36,106 $113,149
------------ ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
arising during the period................ (3,765) 935 (2,192) (13)
Less reclassification adjustment for
gains included in net income............. (246) (151) (427) (447)
Minimum pension liability adjustment............ - - - 780
Mark-to-market adjustment for certain
derivative transactions:
Initial implementation of SFAS 133
designated cash flow hedges............... - - - 6,148
Change in fair market value of
designated cash flow hedges............... (1,036) (18,699) (196) (8,984)
Less reclassification adjustment for
(gains) losses in net income............. 430 (17,255) 773 (17,255)
------------ ------------ ------------ ------------
Total Other Comprehensive Loss.................... (4,617) (35,170) (2,042) (19,771)
------------ ------------ ------------ ------------
Total Comprehensive Income........................ $6,540 $ 14,427 $ 34,064 $ 93,378
============ ============ ============ ============
The accompanying notes are an integral part of these financial statements.
11
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF EARNINGS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands, except per share amounts)
Operating Revenues:
Electric...................................... $220,516 $577,730 $424,479 $1,122,324
Gas........................................... 43,968 87,084 153,169 279,020
Unregulated businesses........................ - 1,277 - 1,277
------------ ------------ ------------ ------------
Total operating revenues.................... 264,484 666,091 577,648 1,402,621
------------ ------------ ------------ ------------
Operating Expenses:
Cost of energy sold........................... 122,692 433,841 277,800 930,939
Administrative and general.................... 35,917 38,768 63,742 78,256
Energy production costs....................... 34,202 37,878 69,173 72,903
Depreciation and amortization................. 24,980 23,929 49,753 48,148
Transmission and distribution costs........... 15,451 15,080 31,988 30,357
Taxes, other than income taxes................ 8,045 7,839 16,081 15,056
Income taxes.................................. 2,733 28,209 12,505 69,115
------------ ------------ ------------ ------------
Total operating expenses.................... 244,020 585,544 521,042 1,244,774
------------ ------------ ------------ ------------
Operating income............................ 20,464 80,547 56,606 157,847
------------ ------------ ------------ ------------
Other Income and Deductions:
Other income.................................. 6,321 13,852 19,493 27,229
Other deductions.............................. (1,626) (35,918) (3,752) (44,735)
Income tax (expense) benefit.................. (2,511) 7,478 (6,884) 5,552
------------ ------------ ------------ ------------
Net other income and deductions............. 2,184 (14,588) 8,857 (11,954)
------------ ------------ ------------ ------------
Income before interest charges.............. 22,648 65,959 65,463 145,893
Interest Charges................................ 11,995 16,362 29,956 32,744
------------ ------------ ------------ ------------
Net Earnings Before Preferred Stock Dividends 10,653 49,597 35,507 113,149
Preferred Stock Dividend Requirements........... 147 147 293 293
------------ ------------ ------------ ------------
Net Earnings.................................... $ 10,506 $ 49,450 $ 35,214 $ 112,856
============ ============ ============ ============
The accompanying notes are an integral part of these financial statements.
12
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
-------------- --------------
(Unaudited)
(In thousands)
ASSETS
Utility Plant:
Electric plant in service...................................... $2,179,468 $2,118,417
Gas plant in service........................................... 595,397 575,350
Common plant in service and plant held for future use.......... 20,883 45,223
-------------- --------------
2,795,748 2,738,990
Less accumulated depreciation and amortization................. 1,268,873 1,234,629
-------------- --------------
1,526,875 1,504,361
Construction work in progress.................................. 228,965 249,656
Nuclear fuel, net of accumulated amortization of
$19,533 and $16,954........................................ 26,586 26,940
-------------- --------------
Net utility plant............................................ 1,782,426 1,780,957
-------------- --------------
Other Property and Investments:
Other investments.............................................. 431,917 446,784
Non-utility property, net of accumulated depreciation of
$1,580 for December 31, 2001............................... 966 1,784
-------------- --------------
Total other property and investments......................... 432,883 448,568
-------------- --------------
Current Assets:
Cash and cash equivalents...................................... 16,879 14,677
Accounts receivables, net of allowance for uncollectible
accounts of $17,075 and $18,025............................ 106,087 147,787
Other receivables.............................................. 48,642 52,158
Inventories.................................................... 36,702 36,483
Regulatory assets.............................................. 100 10,473
Short-term investments......................................... - 45,111
Other current assets........................................... 17,921 21,477
-------------- --------------
Total current assets......................................... 226,331 328,166
-------------- --------------
Deferred Charges:
Regulatory assets.............................................. 196,245 187,475
Prepaid retirement costs....................................... 39,176 18,273
Other deferred charges......................................... 87,182 44,199
-------------- --------------
Total deferred charges....................................... 322,603 249,947
-------------- --------------
$2,764,243 $2,807,638
============== ==============
The accompanying notes are an integral part of these financial statements.
13
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2002 2001
--------------- ---------------
(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands)
Capitalization:
Common stockholders' equity:
Common stock................................................... $ 195,589 $ 195,589
Additional paid-in capital..................................... 430,043 430,043
Accumulated other comprehensive loss, net of tax............... (28,615) (28,996)
Retained earnings.............................................. 229,741 288,388
--------------- ---------------
Total common stockholders' equity........................... 826,758 885,024
Minority interest................................................. 12,056 11,652
Cumulative preferred stock without mandatory
redemption requirements...................................... 12,800 12,800
Long-term debt.................................................... 953,912 953,884
--------------- ---------------
Total capitalization........................................ 1,805,526 1,863,360
--------------- ---------------
Current Liabilities:
Short-term debt................................................... 100,000 35,000
Intercompany debt................................................. 11,126 -
Accounts payable.................................................. 95,126 120,918
Intercompany accounts payable..................................... 19,259 -
Accrued interest and taxes........................................ 64,267 72,022
Other current liabilities......................................... 67,781 101,697
--------------- ---------------
Total current liabilities................................... 357,559 329,637
--------------- ---------------
Deferred Credits:
Accumulated deferred income taxes................................... 131,606 120,153
Accumulated deferred investment tax credits......................... 43,149 44,714
Regulatory liabilities.............................................. 51,764 52,890
Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163
Accrued postretirement benefit costs................................ 15,154 14,929
Other deferred credits.............................................. 345,3220 367,792
--------------- ---------------
Total deferred credits........................................... 601,158 614,641
--------------- ---------------
$2,764,243 $2,807,638
=============== ===============
The accompanying notes are an integral part of these financial statements.
14
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
-----------------------------
2002 2001
------------- -------------
(In thousands)
Cash Flows From Operating Activities:
Net earnings......................................................... $ 35,507 $ 113,149
Adjustments to reconcile net earnings to net cash flows
from operating activities:
Depreciation and amortization.................................... 50,946 53,083
Other, net....................................................... (24,995) 29,117
Changes in certain assets and liabilities:
Accounts receivables........................................... 41,700 (42,693)
Other assets................................................... (9,026) 31,405
Accounts payable............................................... (25,792) 1,081
Accrued taxes.................................................. (6,658) 48,698
Other liabilities.............................................. 23,132 23,641
------------- -------------
Net cash flows provided by operating activities................ 84,814 257,481
------------- -------------
Cash Flows Used for Investing Activities:
Utility plant additions.............................................. (125,078) (115,941)
Redemption of short-term investments................................. 45,000 -
Return of principal of PVNGS lessor notes............................ 8,996 8,535
Other investing...................................................... (2,618) (5,544)
------------- -------------
Net cash flows used for investing activities................... (73,700) (112,950)
------------- -------------
Cash Flows Used for Financing Activities:
Borrowings........................................................... 65,000 -
Exercise of employee stock options................................... - (2,682)
Dividends paid....................................................... (51,450) (15,935)
Other financing...................................................... (405) (285)
Change in intercompany accounts...................................... (22,057) -
------------- -------------
Net cash flows provided by (used by) financing activities...... (8,912) (18,902)
------------- -------------
Increase in Cash and Cash Equivalents.................................. 2,202 125,629
Beginning of Period.................................................... 14,677 107,691
------------- -------------
End of Period.......................................................... $ 16,879 $233,320
============= =============
Supplemental Cash Flow Disclosures:
Interest paid........................................................ $ 30,241 $ 31,382
============= =============
Capitalized interest................................................. $ 3,995 $ -
============= =============
Income taxes paid, net .............................................. $ 31,514 $ 52,150
============= =============
The accompanying notes are an integral part of these financial statements.
15
PUBLIC SERVICE COMPANY OF NEW MEXICO
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(In thousands)
Net Earnings....................................... $10,653 $49,597 $35,507 $113,149
------------ ------------ ------------ ------------
Other Comprehensive Income (Loss),
net of tax:
Unrealized gain (loss) on securities:
Unrealized holding gains (losses)
arising during the period.................. (903) 935 231 (13)
Less reclassification adjustment for
gains included in net income............... (246) (151) (427) (447)
Minimum pension liability adjustment............. - - - 780
Mark-to-market adjustment for certain
derivative transactions:
Initial implementation of SFAS 133
designated cash flow hedges................ - - - 6,148
Change in fair market value of
designated cash flow hedges................ (1,036) (20,317) (196) (8,984)
Less reclassification adjustment for
(gains) losses in cash flow hedges......... 430 (15,637) 773 (17,255)
------------ ------------ ------------ ------------
Total Other Comprehensive Income (Loss)............ (1,755) (35,170) 381 (19,771)
------------ ------------ ------------ ------------
Total Comprehensive Income......................... $ 8,898 $ 14,427 $35,888 $ 93,378
============ ============ ============ ============
The accompanying notes are an integral part of these financial statements.
16
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Company Overview
PNM Resources, Inc. (the "Holding Company"), is an investor-owned holding
company of energy and energy related companies. Its principal subsidiary, Public
Service Company of New Mexico ("PNM"), is an integrated public utility primarily
engaged in the generation, transmission, distribution and sale and trading of
electricity; transmission, distribution and sale of natural gas within the state
of New Mexico and the sale and trading of electricity in the Western United
States.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Holding Company, the Holding Company became the parent
company of PNM. Prior to the share exchange, the Holding Company had existed as
a subsidiary of PNM. The new parent company began trading on the New York Stock
Exchange under the PNM symbol beginning on December 31, 2001.
(2) Accounting Policies and Responsibilities for Financial Statements
In the opinion of management of the Holding Company and PNM, the
accompanying interim consolidated financial statements present fairly the
Companies' financial position at June 30, 2002 and December 31, 2001, the
consolidated results of their operations for the three and six months ended June
30, 2002 and 2001 and the consolidated statements of cash flows for the six
months ended June 30, 2002 and 2001. These statements are presented in
accordance with the rules and regulations of the United States Securities and
Exchange Commission ("SEC"). Accordingly, they are unaudited, and certain
information and footnote disclosures normally included in the Companies' annual
consolidated financial statements have been condensed or omitted, as permitted
under the applicable rules and regulations. Readers of these statements should
refer to the Companies' audited consolidated financial statements and notes
thereto for the year ended December 31, 2001, which are included on the
Companies' Annual Report on Form 10-K for the year ended December 31, 2001. The
results of operations presented in the accompanying financial statements are not
necessarily representative of operations for an entire year.
(3) Presentation
The Notes to Consolidated Financial Statements of PNM Resources, Inc. and
Subsidiaries and PNM (collectively the "Company"), are presented on a combined
basis. The Holding Company assumed substantially all of the corporate activities
of PNM on December 31, 2001. These activities are billed to PNM on a cost basis
to the extent they are for the corporate management of PNM. In January 2002,
Avistar, Inc. ("Avistar") and certain inactive subsidiaries were dividended to
the Holding Company pursuant to an order from the New Mexico Public Regulation
Commission ("PRC"). The reader of the Notes to Consolidated Financial Statements
should assume that the information presented applies to the consolidated results
of operations and financial position of both PNM Resources, Inc. and
Subsidiaries and PNM, except where the context or references clearly indicate
otherwise. Discussions regarding specific contractual obligations generally
reference the company that is legally obligated.
17
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In the case of contractual obligations of PNM, these obligations are
consolidated with the Company under generally accepted accounting principles
("GAAP"). Broader operational discussion refers to the Company.
(4) Segment Information
As it currently operates, the Company's principal business segments are
Utility Operations, which include Electric Services ("Electric") and Gas
Services ("Gas"), and Generation and Trading Operations ("Generation and
Trading"). Electric consists of two major business lines that include
distribution and transmission. The transmission business line does not meet the
definition of a segment due to its immateriality and is combined with the
distribution business line for disclosure purposes.
UTILITY OPERATIONS
Electric
PNM provides retail electric service, regulated by the PRC, to a large
area of north central New Mexico, including the cities of Albuquerque and Santa
Fe, and certain other areas of New Mexico. PNM owns or leases 2,890 circuit
miles of transmission lines, interconnected with other utilities in New Mexico
and south and east into Texas, west into Arizona, and north into Colorado and
Utah.
Electric exclusively acquires its electricity sold to retail customers
from Generation and Trading Operations. Intersegment purchases from Generation
and Trading Operations are priced using internally developed transfer pricing
and are not based on market rates. Customer rates for electric service are set
by the PRC based on the recovery of the cost of power production and a rate of
return that includes certain generation assets that are part of Generation and
Trading Operations, among other things.
Gas
PNM's gas operations distribute natural gas to most of the major
communities in New Mexico, including Albuquerque and Santa Fe. PNM's customer
base includes both sales-service customers and transportation-service customers.
In the first quarter of 2001, Generation and Trading Operations procured
its gas fuel supply from Gas. Beginning with the second quarter of 2001,
Generation and Trading Operations began procuring its gas supply independently
of Gas and contracted with Gas for transportation services only.
18
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
GENERATION AND TRADING OPERATIONS
Generation and Trading Operations serve four principal markets. These
include sales to PNM's Utility Operations to cover retail electric demand, sales
to firm-requirements wholesale customers, other contracted sales to third
parties for a specified amount of capacity (measured in megawatts-MW) or energy
(measured in megawatt hours-MWh) over a given period of time and energy sales
made on an hourly basis at fluctuating, spot-market rates. In addition to
generation capacity, PNM purchases power in the open market. As of June 30,
2002, the total net generation capacity of facilities owned or leased by the
Company was 1,733 MW, including a 132 MW power purchase contract accounted for
as an operating lease.
UNREGULATED
The Holding Company's wholly-owned subsidiary, Avistar, was formed in
August 1999 as a New Mexico corporation and is currently engaged in certain
unregulated and non-utility businesses. Unregulated also includes immaterial
corporate activities and eliminations. The immaterial corporate activities were
assumed by the Holding Company on December 31, 2001.
RISKS AND UNCERTAINTIES
The Company's future results may be affected by changes in regional
economic conditions; the outcome of labor negotiations with union employees;
fluctuations in fuel, purchased power and gas prices; the actions of utility
regulatory commissions; changes in law and environmental regulations, the
performance of PNM's generating units, the success of any generation expansion
and external factors such as the weather. As a result of state and federal
regulatory reforms, the public utility industry is undergoing a fundamental
change. As this occurs, the electric generation business is transforming into a
competitive marketplace. The Company's future results will be impacted by its
ability to recover its stranded costs, incurred previously in providing power
generation to electric service customers, the market price of electricity and
natural gas costs and the costs of transition to an unregulated status. In
addition, as a result of deregulation, the Company may face competition from
companies with greater financial and other resources. However, as a result of
the energy crisis in California, plans for restructuring the industry are
undergoing fundamental review. Any reforms that may be made to existing plans
for restructuring the industry will also affect the Company's future results.
19
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the three months
ended June 30, 2002 and 2001 is as follows:
Utility
----------------------------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............ $140,322 $43,968 $184,290 $80,194 $ 85 $264,569
Intersegment revenues......... 177 470 647 86,012 (86,659) -
Depreciation and amortization.... 8,346 5,076 13,422 10,573 1,222 25,217
Interest income.................. 37 - 37 394 9,299 9,730
Interest charges................. 5,737 3,316 9,053 3,403 2,233 14,689
Income tax expense (benefit)
from continuing operations..... 5,262 (1,393) 3,869 941 763 5,573
Operating income (loss).......... 13,730 (216) 13,514 4,837 1,098 19,449
Segment net income (loss)........ 8,030 (2,127) 5,903 1,513 3,741 11,157
Total assets..................... 771,770 449,695 1,221,465 1,453,900 264,484 2,939,849
Gross property additions......... 13,610 11,035 24,645 31,886 1,830 58,361
2001:
Operating revenues:
External customers............ $136,368 $87,084 $223,452 $441,362 $ 1,277 $666,091
Intersegment revenues......... 177 - 177 83,396 (83,573) -
Depreciation and amortization.... 8,066 5,333 13,399 10,521 9 23,929
Interest income.................. 543 172 715 935 11,274 12,924
Interest charges................. 4,279 2,957 7,236 9,096 30 16,362
Operating income................. 13,514 2,296 15,810 58,694 6,043 80,547
Income tax expense (benefit)
from continuing operations..... 5,256 (380) 4,876 30,439 (14,384) 20,931
Segment net income (loss)........ 8,021 (580) 7,441 46,448 (4,292) 49,597
Total assets..................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532
Gross property additions......... 17,065 10,884 27,949 23,916 4,696 56,561
20
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized financial information by business segment for the six months
ended June 30, 2002 and 2001 is as follows:
Utility
---------------- ---------------- Generation
Electric Gas Total and Trading Unregulated Consolidated
-------- --- ----- ----------- ----------- ------------
(In thousands)
2002:
Operating revenues:
External customers............ $275,565 $153,169 $428,734 $148,914 $ 917 $ 578,565
Intersegment revenues......... 354 470 824 167,962 (168,786) -
Depreciation and amortization.... 16,901 10,388 27,289 21,480 1,227 49,996
Interest income.................. 355 81 436 795 20,331 21,562
Interest charges................. 11,572 6,634 18,206 6,871 4,738 29,815
Income tax expense
from continuing operations..... 11,198 4,318 15,516 2,284 1,981 19,781
Operating income................. 28,747 11,877 40,624 10,418 1,094 52,136
Segment net income............... 17,089 6,587 23,676 3,456 8,974 36,106
Total assets..................... 771,770 449,695 1,221,465 1,453,900 264,484 2,939,849
Gross property additions......... 26,466 17,578 44,044 80,431 3,306 127,781
2001:
Operating revenues:
External customers............ $270,714 $279,020 $549,734 $851,610 $ 1,277 $1,402,621
Intersegment revenues......... 354 - 354 164,313 (164,667) -
Depreciation and amortization.... 16,091 10,623 26,714 21,416 18 48,148
Interest income.................. 1,000 342 1,342 1,480 22,315 25,137
Interest charges................. 8,552 5,942 14,494 18,190 60 32,744
Income tax expense (benefit)
from continuing operations..... 12,078 4,689 16,767 65,561 (18,765) 63,563
Operating income (loss).......... 28,040 12,803 40,843 116,800 204 157,847
Segment net income (loss)........ 18,431 7,156 25,587 100,044 (12,482) 113,149
Total assets..................... 743,780 467,970 1,211,750 1,585,635 276,147 3,073,532
Gross property additions......... 28,505 17,458 45,963 59,251 6,159 111,373
(5) Financial Instruments
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices, interest rates of future
debt issuances and adverse market changes for investments held by the Company's
various trusts. The Company also uses certain derivative instruments for bulk
power electricity trading purposes in order to take advantage of favorable price
movements and market timing activities in the wholesale power markets.
The Company is exposed to credit risk in the event of non-performance or
non-payment by counterparties of its financial derivative instruments. The
Company uses a credit management process to assess and monitor the financial
conditions of counterparties. The Company's credit risk with its largest
counterparty as of June 30, 2002 was $4.5 million.
21
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Contracts
Pursuant to a 1997 order issued by the NMPUC, predecessor to the PRC, PNM
has entered into various financial instruments to hedge certain portions of
natural gas supply contracts in order to protect PNM's natural gas customers
from the risk of adverse price fluctuations in the natural gas market. The
financial impact of all hedge gains and losses from these instruments is
recoverable through PNM's purchased gas adjustment clause ("PGAC"). As a result,
earnings are not affected by gains or losses generated by these instruments.
PNM purchased gas options, a type of hedge, to protect its natural gas
customers from price risk during the 2001-2002 heating season. PNM expended $9.4
million to purchase options that limit the maximum amount PNM would pay for gas
during the winter heating season. PNM recovered its actual hedging expenditures
as a component of the PGAC during the months of October 2001 through February
2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were
substantially lower than the previous year, the hedges placed expired
unexercised.
PNM also purchased gas options for the 2002-2003 heating season. PNM
expended $6.0 million to purchase options that limit the maximum amount PNM
would pay for gas during the winter heating season. PNM plans to recover its
actual hedging expenditures as a component of the PGAC during the months of
October 2002 through February 2003 in equal allotments of $1.2 million.
Electricity Trading Contracts
For the six months ended June 30, 2002, Generation and Trading Operations
settled trading contracts for the sale of electricity that generated $20.6
million of electric revenues by delivering 584,800 MWh. The Company purchased
$35.9 million or 673,800 MWh of electricity to support these contractual sales
and other open market sales opportunities. For the six months ended June 30,
2001, Generation and Trading Operations settled trading contracts for the sale
of electricity that generated $37.3 million of electric revenues by delivering
225,000 MWh. The Company purchased $36.2 million or 205,000 MWh of electricity
to support these contractual sales and other open market sales opportunities.
As of June 30, 2002, the Company had open trading contract positions to
buy $33.3 million and to sell $51.1 million of electricity. At June 30, 2002,
the Company had a gross mark-to-market gain (asset position) on these trading
contracts of $6.4 million and gross mark-to-market loss (liability position) of
$20.7 million, with a net mark-to-market loss (liability position) of $14.3
million. The change in mark-to-market valuation is recognized in earnings each
period.
In addition, Generation and Trading Operations enter into forward
physical contracts for the sale of the Company's electric capacity in excess of
its retail and wholesale firm requirements needs, including reserves, or the
purchase of retail and wholesale firm requirements needs, including reserves,
when resource shortfalls exist. The Company generally accounts for these
derivative financial instruments as normal sales and purchases as defined by
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
22
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Instruments and Hedging Activities," ("SFAS 133"), as amended. The Company from
time to time makes forward purchases to serve its retail needs when the cost of
purchased power is less than the incremental cost of its generation. At June 30,
2002, the Company had open forward positions classified as normal sales of
electricity of $18.3 million and normal purchases of electricity of $52.3
million.
Generation and Trading Operations, including both firm commitments and
trading activities, are managed through an asset backed strategy, whereby the
Company's aggregate net open position is covered by its own excess generation
capabilities. The Company is exposed to market risk if its generation
capabilities were disrupted or if its retail load requirements were greater than
anticipated. If the Company were required to cover all or a portion of its net
open contract position, it would have to meet its commitments through market
purchases.
Forward Starting Interest Rate Swaps
PNM currently has $182.0 million of tax-exempt bonds outstanding that are
callable at a premium in December 2002 and August 2003. PNM intends to refinance
these bonds assuming the interest rate of the refinancing does not exceed the
current interest rate of the bonds and has hedged the entire planned
refinancing. In order to take advantage of current low interest rates, PNM
entered into two forward starting interest rate swaps in November and December
2001 and three additional contracts in the first quarter of 2002. PNM designated
these swaps as cash flow hedges. The hedged risks associated with these
instruments are the changes in cash flows related to general moves in interest
rates expected for the refinancing. The swaps effectively cap the interest on
the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit
rating. PNM's assessment of hedge effectiveness is based on changes in the
interest rates and PNM's credit spread. SFAS 133, as amended, provides that the
effective portion of the gain or loss on a derivative instrument designated and
qualifying as a cash flow hedging instrument be reported as a component of other
comprehensive income and be reclassified into earnings in the same period or
periods during which the hedged forecasted transactions affect earnings. Any
hedge ineffectiveness is required to be presented in current earnings. There was
no material hedge ineffectiveness in the six months ended June 30, 2002.
A forward starting swap does not require any upfront premium and captures
changes in the corporate credit component of an investment grade company's
interest rate as well as the underlying Treasury benchmark. The five forward
interest rate starting swaps have termination dates and notional amounts as
follows: one with a termination date of September 17, 2002 for a notional amount
of $46.0 million and four with a termination date of May 15, 2003 for a combined
notional amount of $136.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transactions will be cash settled on the
mandatory unwind date (strike date), corresponding to the refinancing date of
the underlying debt. The settlement will be capitalized as a cost of issuance
and amortized over the life of the debt as a yield adjustment.
23
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Earnings Per Share
In accordance with SFAS No. 128, Earnings per Share, dual presentation of
basic and diluted earnings per share has been presented in the Consolidated
Statements of Earnings. The following reconciliation illustrates the impact on
the share amounts of potential common shares and the earnings per share amounts
for June 30 (in thousands, except per share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
----------- ----------- ----------- -----------
Basic:
Net Earnings from Continuing Operations.............. $11,157 $49,597 $ 36,106 $113,149
----------- ----------- ----------- -----------
Net Earnings......................................... 11,157 49,597 36,106 113,149
Preferred Stock Dividend Requirements................ 147 147 293 293
----------- ----------- ----------- -----------
Net Earnings Applicable to Common Stock.............. $11,010 $49,450 $ 35,813 $112,856
=========== =========== =========== ===========
Average Number of Common Shares Outstanding.......... 39,118 39,118 39,118 39,118
=========== =========== =========== ===========
Net Earnings per Common Share (Basic)................ $ 0.28 $ 1.26 $ 0.92 $ 2.89
=========== =========== =========== ===========
Diluted:
Net Earnings Applicable to Common Stock
Used in basic calculation.......................... $11,010 $49,450 $ 35,813 $112,856
=========== =========== =========== ===========
Average Number of Common Shares Outstanding.......... 39,118 39,118 39,118 39,118
Diluted effect of common stock equivalents (a)....... 468 848 494 664
----------- ----------- ----------- -----------
Average common and common equivalent shares
Outstanding........................................ 39,586 39,966 39,612 39,782
=========== =========== =========== ===========
Net Earnings per Share of Common Stock (Diluted)..... $ 0.28 $ 1.24 $ 0.90 $ 2.84
=========== =========== =========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents
related to out-of-the-money options of 33,462 and 23,785 for the three
months ended and the six months ended June 30, 2002, respectively. There
were no anti-dilutive common stock equivalents in 2001.
(7) Commitments and Contingencies
Construction Commitment
PNM has committed to purchase five combustion turbines for a total cost
of $151.3 million. The turbines are for planned power generation plants with an
estimated cost of construction of approximately $370 million over the next five
years depending on market conditions. PNM has expended $193 million as of June
30, 2002, of which $123 million was for equipment purchases. In November 2001,
PNM broke ground to build Afton Generating Station, a 135 MW simple cycle gas
turbine plant in Southern New Mexico. In February 2002, PNM broke ground to
build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired
generating plant in Southern New Mexico. On June 27, 2002, Lordsburg became
fully operational and will serve the wholesale power market. Contracts have not
24
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
been finalized on the remaining planned construction. These plants are part of
the Company's ongoing competitive strategy of increasing generation capacity
over time. These plants are not anticipated to be added to rate base.
PVNGS Liability and Insurance Matters
The PVNGS participants have financial protection for public liability
resulting from nuclear energy hazards to the full limit of liability under
federal law. This potential liability is covered by primary liability insurance
provided by commercial insurance carriers in the amount of $200 million and the
balance by an industry-wide retrospective assessment program. If losses at any
nuclear power plant covered by the programs exceed the primary liability
insurance limit, the Company could be assessed retrospective adjustments. The
maximum assessment per reactor under the program for each nuclear incident is
approximately $88 million, subject to an annual limit of $10 million per reactor
per incident. Based upon the Company's 10.2% interest in the three PVNGS units,
the Company's maximum potential assessment per incident for all three units is
approximately $27.0 million, with an annual payment limitation of $3 million per
incident. If the funds provided by this retrospective assessment program prove
to be insufficient, Congress could impose revenue raising measures on the
nuclear industry to pay claims.
Aspects of the federal law referred to above (the "Price-Anderson Act"),
which provides for payment of public liability claims in case of a catastrophic
accident involving a nuclear power plant are up for renewal in August 2002.
While existing nuclear power plants would continue to be covered in any event,
the renewal would extend coverage to future nuclear power plants and could
contain amendments that would affect existing plants. A renewal bill was passed
by the House with unanimous consent on November 27, 2001. The House proposed a
change in the annual retrospective premium limit from $10 million to $15 million
per reactor per incident. Additionally, the House proposed to amend the maximum
potential assessment from $88.1 million to $98.7 million per reactor per
incident, taking into account effects of inflation. On March 7, 2002 the Senate
approved a Price-Anderson Act amendment as a part of the comprehensive energy
bill. The Senate version is substantially the same as the Price-Anderson Act in
its current form. Both the current law and the versions approved by the House
and Senate provide for the primary financial protection limit to be the maximum
amount available from private insurance sources. Those sources are currently
being evaluated as to whether the $200 million now available for liability
claims per reactor could be increased to keep pace with inflation. The Company
cannot predict whether or not Congress will renew the Price-Anderson Act or
whether or not an increase will be made to the primary financial protection
layer. A House-Senate Conference Committee has been formed to resolve the
differences between the amendment approved by the House and that approved by the
Senate. In the event the comprehensive energy bill does not pass, it is possible
that the Price-Anderson amendment would be passed as a stand-alone bill.
However, if adopted, certain changes in the law could possibly trigger "Deemed
Loss Events" under the Company's PVNGS leases, absent waiver by the lessors.
Such an occurrence could require the Company to, among other things, (i) pay the
lessor and the equity investor, in return for the investor's interest in PVNGS,
cash in the amount as provided in the lease and (ii) assume debt obligations
relating to the PVNGS lease.
25
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The PVNGS participants maintain "all-risk" (including nuclear hazards)
insurance for damage to, and decontamination of, property at PVNGS in the
aggregate amount of $2.75 billion as of January 1, 2002, a substantial portion
of which must be applied to stabilization and decontamination. The Company has
also secured insurance against portions of the increased cost of generation or
purchased power and business interruption resulting from certain accidental
outages of any of the three units if the outages exceed 8 weeks. The insurance
coverage discussed in this section is subject to certain policy conditions and
exclusions. The Company is a member of an industry mutual insurer. This mutual
insurer provides both the "all-risk" and increased cost of generation insurance
to the Company. In the event of adverse losses experienced by this insurer, the
Company is subject to an assessment. The Company's maximum share of any
assessment is approximately $4.6 million per year.
PVNGS Decommissioning Funding
The Company has a program for funding its share of decommissioning costs
for PVNGS. The nuclear decommissioning funding program is invested in equities
and fixed income instruments in qualified and non-qualified trusts. The results
of the 2002 decommissioning cost study indicated that the Company's share of the
PVNGS decommissioning costs excluding spent fuel disposal would be approximately
$201 million. The estimated market value of the trusts at the end of June 30,
2002 was approximately $54 million.
The Company did not provide any additional funding for the six months
ended June 30, 2002 into the qualified and non-qualified trust funds.
Nuclear Spent Fuel and Waste Disposal
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the
"Waste Act"), the United States Department of Energy ("DOE") is obligated to
accept and dispose of all spent nuclear fuel and other high-level radioactive
wastes generated by all domestic power reactors. Under the Waste Act, the DOE
was to develop the facilities necessary for the storage and disposal of spent
nuclear fuel and to have the first facility in operation by 1998. DOE has
announced that such a repository now cannot be completed before 2010.
The operator of PVNGS has capacity in existing fuel storage pools at
PVNGS which, with certain modifications, could accommodate all fuel expected to
be discharged from normal operation of PVNGS through 2002, and believes it could
augment that storage with the new facilities for on-site dry storage of spent
fuel for an indeterminate period of operation beyond 2002, subject to obtaining
any required governmental approvals. The Company currently estimates that it
will incur approximately $41.0 million (in 1998 dollars) over the life of PVNGS
for its share of the fuel costs related to the on-site interim storage of spent
nuclear fuel during the operating life of the plant. The Company accrues these
costs as a component of fuel expense, meaning the charges are accrued as the
fuel is burned. The operator of PVNGS currently believes that spent fuel storage
or disposal methods will be available for use by PVNGS to allow its continued
operation beyond 2002.
26
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Explosion
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. The Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau, which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with several claims for property and
business interruption damages have been resolved. The Company believes that the
final outcome of this matter will not have a material impact on the results of
operations and financial position of the Company.
Western Resources Transaction
On November 9, 2000, the Company and Western Resources announced that
both companies' Boards of Directors approved an agreement under which the
Company would acquire the Western Resources electric utility operations in a
tax-free, stock-for-stock transaction. The agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
In July, 2001, the Kansas Corporation Commission ("KCC") issued two
orders. The first order declared the split-off required by the agreement to be
unlawful as designed, with or without a merger. The second order decreased rates
for Western Resources, despite a request for an increase of $151 million. After
rehearing the KCC established the rate decrease at $15.7 million. On October 3,
2001, the KCC issued an Order on Reconsideration reaffirming its decision that
the split-off as designed in the agreement was unlawful with or without a
merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state
court. On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition, the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
27
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect. However, the Company
subsequently received a letter dated May 28, 2002, from counsel for Western
Resources purporting to terminate the agreement and demanding payment of a $25
million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the
Company in New York state court alleging breach of contract and fraud. Western
Resources alleged that the Company's January 7 letter constituted a withdrawal
or adverse modification of the Company's adoption of the agreement or
recommendation that its shareholders approve the agreement. As a result, Western
Resources claims that the Company is liable for a $25 million termination fee
plus costs and expenses (including attorneys fees) incurred in connection with
the litigation. Western Resources also claims that the Company committed fraud
by not timely disclosing to Western Resources its intentions not to proceed with
the transaction and is seeking additional unspecified damages. The Company
believes that the counterclaims filed by Western Resources are without merit and
intends to vigorously defend itself against them. The Company also intends to
vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment
and for Dismissal of Counterclaims and Defenses.
The Company is unable to predict the ultimate outcome of its litigation
with Western Resources.
Other
There are various claims and lawsuits pending against the Company and
certain of its subsidiaries. The Company is also subject to federal, state and
local environmental laws and regulations, and is currently participating in the
investigation and remediation of numerous sites. In addition, the Company
periodically enters into financial commitments in connection with business
operations. It is not possible at this time for the Company to determine fully
the effect of all litigation on its consolidated financial statements. However,
the Company has recorded a liability where the litigation effects can be
estimated and where an outcome is considered probable. The Company does not
expect that any known lawsuits, environmental costs and commitments will have a
material adverse effect on its financial condition or results of operations.
(8) Environmental Issues
The normal course of operations of the Company necessarily involves
activities and substances that expose the Company to potential liabilities under
laws and regulations protecting the environment. Liabilities under these laws
and regulations can be material and in some instances may be imposed without
regard to fault, or may be imposed for past acts, even though the past acts may
28
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
have been lawful at the time they occurred. Sources of potential environmental
liabilities include the Federal Comprehensive Environmental Response
Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities when site assessments
or remedial actions are probable and a range of reasonably likely cleanup costs
can be estimated. The Company reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each identified
site using currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, the Company records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities at undiscounted
amounts).
The Company's recorded estimated minimum liability to remediate its
identified sites is $8.8 million. The ultimate cost to clean up the Company's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature
of contamination; the scarcity of reliable data for identified sites; and the
time periods over which site remediation is expected to occur.
For the six months ended June 30, 2002 and 2001, the Company spent $0.8
million and $0.5 million, respectively, for remediation. The majority of the
June 30, 2002 environmental liability is expected to be paid over the next five
years, funded by cash generated from operations. Future environmental
obligations are not expected to have a material impact on the results of
operations or financial condition of the Company.
(9) New and Proposed Accounting Standards
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the FASB issued SFAS
143. The statement requires the recognition of a liability for legal obligations
associated with the retirement of a tangible long-lived asset that result from
the acquisition, construction or development and/or the normal operation of a
long-lived asset. The asset retirement obligation must be recognized at its fair
value when incurred. The cost of the asset retirement obligation has to be
capitalized by increasing the carrying amount of the related long-lived asset by
the same amount as the liability. This cost must be expensed using a systematic
and rational method over the related asset's useful life. SFAS 143 is effective
for the Company beginning January 1, 2003. The Company is currently assessing
the impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement amends certain requirements of the
previously issued pronouncement on asset impairment, SFAS 121. SFAS 144 removes
29
PNM RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
goodwill from the scope of SFAS 121, provides for a probability-weighted cash
flow estimation approach for estimating possible future cash flows, and
establishes a "primary asset" approach for a group of assets and liabilities
that represents the unit of accounting to be evaluated for impairment. In
addition, SFAS 144 changes the measurement of long-lived assets to be disposed
of by sale, as accounted for by Accounting Principles Board Opinion No. 30.
Under SFAS 144, discontinued operations are no longer measured on a net
realizable value basis, and their future operating losses are no longer
recognized before they occur. The Company does not believe SFAS 144 will have a
material effect on its future operating results or financial position.
Statement of Financial Accounting Standards No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This
statement updates and clarifies existing accounting pronouncements for treatment
of gains and losses from extinguishment of debt and eliminates an inconsistency
between required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have similar economic effects as
sale-leaseback transactions. According to the old policy, gains and losses from
extinguishment of debt were classified as extraordinary gains and losses. The
current statement permits gains and losses from extinguishment of debt to be
classified as ordinary and included in income from operations, unless they are
unusual in nature or occur infrequently and therefore included as an
extraordinary item.
Emerging Issues Task Force ("EITF") Issue 02-03 "Recognition and
Reporting of Gains and Losses" on Energy Trading Contracts under EITF Issues No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts
in Applying Issue No. 98-10." This EITF issue addresses various aspects of the
accounting for contracts involved in energy trading and risk management
activities. The EITF concluded that all mark-to-market gains and losses on
energy trading contracts should be shown net in the income statement whether or
not settled physically. The EITF did not reach a consensus and continues to
debate whether the recognition of unrealized gains and losses at inception of an
energy trading contract is appropriate in the absence of quoted market prices or
current market transactions for contracts with similar terms. The EITF also
expanded the disclosure requirements for energy trading activities.
Implementation of the consensus for recording energy trading activities net is
effective for the Company beginning with its 2002 third quarter financial
statements. Comparative financial statements for prior periods are required to
be reclassified to conform to the EITF's consensus. The Company is currently
assessing the impact of implementing EITF Issue No. 02-03 and is unable to
predict its effect on the Company's presentation of operating results. The SEC
has indicated that financial statement reclassifications related to periods
previously audited by Arthur Andersen, LLP ("Arthur Andersen") may require the
successor auditor to audit the prior periods and issue a new audit report.
Arthur Andersen audited the Company's financial statements for the fiscal years
2001 and 2000.
30
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The Management's Discussion and Analysis of Financial Condition and
Results of Operations for PNM Resources, Inc. (the "Holding Company") and
Subsidiaries and Public Service Company of New Mexico ("PNM") (collectively the
Company), is presented on a combined basis. The Holding Company assumed
substantially all of the corporate activities of PNM on December 31, 2001. These
activities are billed to PNM on a cost basis to the extent they are for the
corporate management of PNM. In January 2002, Avistar, Inc. ("Avistar") and
certain inactive subsidiaries were dividended to the Holding Company pursuant to
an order from the PRC. The reader of this Management's Discussion and Analysis
of Financial Condition and Results of Operations should assume that the
information presented applies to consolidated results of operations and
financial position of both PNM Resources, Inc. and Subsidiaries and PNM, except
where the context or references clearly indicate otherwise. Discussions
regarding specific contractual obligations generally reference the company that
is legally obligated. In the case of contractual obligations of PNM, these
obligations are consolidated with PNM Resources, Inc. and Subsidiaries under
GAAP. Broader operational discussion references the Company.
The following is management's assessment of the Company's financial
condition and the significant factors affecting the results of operations. This
discussion should be read in conjunction with the Company's consolidated
financial statements and its annual report on Form 10-K for the year ended
December 31, 2001. Trends and contingencies of a material nature are discussed
to the extent known and considered relevant.
OVERVIEW
PNM Resources, Inc. (the "Holding Company"), is an investor-owned holding
company of energy and energy related companies. Its principal subsidiary, Public
Service Company of New Mexico ("PNM"), is an integrated public utility primarily
engaged in the generation, transmission, distribution and sale and trading of
electricity; transmission, distribution and sale of natural gas within the state
of New Mexico and the sale and trading of electricity in the Western United
States.
Upon the completion on December 31, 2001, of a one-for-one share exchange
between PNM and the Holding Company, the Holding Company became the parent
company of PNM. Prior to the share exchange, the Holding Company had existed as
a subsidiary of PNM. The new parent company began trading on the New York Stock
Exchange under the same PNM symbol beginning on December 31, 2001.
31
COMPETITIVE STRATEGY
The Company is positioned as a "merchant utility," primarily operating as
a regulated energy service provider also engaged in the sale and trading of
electricity in the competitive energy market place. As a utility, PNM has an
obligation to serve its customers under the jurisdiction of the New Mexico
Public Regulation Commission ("PRC"). As a merchant, PNM markets excess
production from the utility, as well as unregulated generation into a
competitive market place. The Company also has an electric power trading area
focused on purchasing wholesale electricity in the market for future resale or
to provide energy to jurisdictional customers in New Mexico when the Company's
generation assets cannot satisfy demand. The marketing and trading operations
utilize an asset-backed trading strategy, whereby the Company's aggregate net
open position for the sale of electricity is covered by the Company's excess
generation capabilities. The benefits of the merchant operations are shared with
retail customers based on a negotiated settlement in proportion to capacity
owned, expended effort, and risk assumed. Non-regulated assets may be part of
the utility company or owned by an affiliate of the utility company, which could
be a subsidiary of the holding company. Currently, all non-regulated assets,
except Avistar, are part of the utility. Both retail customers and shareholders
benefit from this combination.
The Electric and Gas Services strategy is directed at supplying
reasonably priced and reliable energy to retail customers through
customer-driven operational excellence, high quality customer service, cost
efficient processes, and improved overall organizational performance.
The Generation and Trading strategy calls for increased asset-backed
trading and generation capacity supported by long-term contracts, balanced with
stringent risk management policies. The Company's future growth plans call for
approximately 50% of its new generation and 70% of its total portfolio to be
committed through long-term contracts, including its sales to retail customers.
Such growth will be dependent on market developments, and upon the Company's
ability to generate funds for the Company's future expansion.
(Intentionally left blank)
32
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002
Compared to Three Months Ended June 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the three
months ended June 30, 2002 were $11.0 million, a 77.7% decrease in net earnings
from $49.5 million in 2001. This decrease primarily reflects the slowdown in the
wholesale electric market, where both prices and trading activity were lower
than the prior year period. Despite the slow-down in the wholesale electricity
market, PNM's electric utility operations recorded an operating income growth of
1.6%. This growth came from a combination of load growth and cost savings,
demonstrating the balance the regulated utility provides in the Company's
"merchant utility" strategy.
Earnings for the second quarter in 2001 were affected by certain
non-recurring charges; however, there were no non-recurring charges for the
second quarter in 2002. These special items are detailed in the individual
business segment discussions below. The following table enumerates these
non-recurring charges and shows their effect on diluted earnings per share, in
thousands, except per share amounts.
Three Months Ended
June 30,
--------------------------------------------------
2002 2001
------------------------ ------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
----------- ------------ ------------- ----------
(Income)/Expense
Net Earnings Available for Common
Shareholders.................................. $11,010 $ 0.28 $49,450 $ 1.24
----------- ------------ ------------- ----------
Adjustment for Special Gains and Charges
(net of income tax effects):
Contribution to PNM Foundation................. - - (3,021) (0.07)
Write-off of non-recoverable coal mine
decommissioning costs........................ - - (7,840) (0.20)
Write-off of an Avistar investment............. - - (406) (0.01)
Western Resources acquisition costs............ - - (2,331) (0.06)
----------- ------------ ------------- ----------
Total........................................ - - (13,598) (0.34)
----------- ------------ ------------- ----------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
and Charges................................... $ 11,010 $ 0.28 $63,048 $ 1.58
=========== ============ ============ ==========
To adjust reported net earnings and diluted earnings per share to exclude
the non-recurring charges, such charges, net of income tax benefit, are added
back to reported net earnings under GAAP.
33
The following discussion is based on the financial information presented
in the Consolidated Financial Statements - Segment Information note in the Notes
to Consolidated Financial Statements.
Utility Operations
Electric
The table below sets forth the operating results for the Electric
business segment.
Electric
Three Months Ended June 30,
-------------------------------------
2002 2001 Variance
---------------- ----------------- ---------------
(In thousands)
Operating revenues:
External customers....................... $140,322 $136,368 $ 3,954
Intersegment revenues.................... 177 177 -
---------------- ----------------- ---------------
Total revenues........................... 140,499 136,545 3,954
---------------- ----------------- ---------------
Cost of energy sold........................ 1,020 1,252 (232)
Intersegment purchases..................... 86,012 83,396 2,616
---------------- ----------------- ---------------
Total cost of energy..................... 87,032 84,648 2,384
---------------- ----------------- ---------------
Gross margin............................... 53,467 51,897 1,570
---------------- ----------------- ---------------
Administrative and other................... 14,144 12,799 1,345
Depreciation and amortization.............. 8,346 8,066 280
Transmission and distribution costs........ 8,805 8,334 471
Taxes other than income taxes.............. 3,205 3,133 72
Income taxes............................... 5,237 6,051 (814)
---------------- ----------------- ---------------
Total non-fuel operating expenses........ 39,737 38,383 1,354
---------------- ----------------- ---------------
Operating income........................... $ 13,730 $ 13,514 $ 216
---------------- ----------------- ---------------
Operating revenues increased $4.0 million or 2.9% for the period to
$140.5 million. Retail electricity delivery grew 3.1% to 1.83 million MWh in
2002 compared to 1.77 million MWh delivered in the prior year period, resulting
in increased revenues of $4.0 million period-over-period. This volume increase
was the result of a weather-driven increase in consumption and continued load
growth of 3.1%, which is consistent with historical levels. Period over period,
customer growth was approximately 2%, also consistent with historical levels.
(Intentionally left blank)
34
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
Three Months Ended
June 30,
2002 2001
------------ ------------
(In thousands)
Residential.................. $45,408 $43,332
Commercial................... 62,867 61,126
Industrial................... 20,792 20,488
Other........................ 11,432 11,599
------------ ------------
$140,499 $136,545
============ ============
Average customers............ 384,000 377,000
============ ============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Three Months Ended
June 30,
2002 2001
------------ ------------
Residential................... 530,300 506,712
Commercial.................... 827,335 806,003
Industrial.................... 405,571 396,832
Other......................... 62,491 61,667
------------ ------------
1,825,697 1,771,214
============ ============
The gross margin, or operating revenues minus cost of energy sold,
increased $1.6 million, which reflects the increased energy sales. Electric
exclusively purchases power from Generation and Trading at internally developed
prices, which are not based on market rates. These intercompany revenues and
expenses are eliminated in the consolidated results.
Total non-fuel operating expenses increased $1.4 million or 3.5%.
Administrative and other increased $1.3 million or 10.5% due to higher
administrative costs allocated from Corporate. Depreciation and amortization
increased $0.3 million or 3.5% for the period due to a higher depreciable plant
base. Transmission and distribution costs increased $0.5 million or 5.6%
primarily due to an increase in overhead line maintenance to enhance system
reliability. Income taxes, which include taxes for interest charges, decreased
$0.8 million or 13.5% due to the decline in pre-tax income.
35
Gas
The table below sets forth the operating results for the Gas business
segment.
Gas
Three Months Ended June 30,
--------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers........................ $ 43,968 $ 87,084 $ (43,116)
Intersegment revenues..................... 470 - 470
-------------- --------------- ---------------
Total revenues............................ 44,438 87,084 (42,646)
-------------- --------------- ---------------
Total cost of energy...................... 18,922 57,745 (38,823)
-------------- --------------- ---------------
Gross margin................................ 25,516 29,339 (3,823)
-------------- --------------- ---------------
Administrative and other.................... 14,333 13,440 893
Depreciation and amortization............... 5,076 5,333 (257)
Transmission and distribution costs......... 6,594 6,647 (53)
Taxes other than income taxes............... 2,043 2,056 (13)
Income taxes................................ (2,314) (433) (1,881)
-------------- --------------- ---------------
Total non-fuel operating expenses......... 25,732 27,043 (1,311)
-------------- --------------- ---------------
Operating income (loss)..................... $ (216) $ 2,296 $ (2,512)
-------------- --------------- ---------------
Operating revenues decreased $42.6 million or 49.0% for the period to
$44.4 million, primarily as the result of lower natural gas prices during the
second quarter of 2002 as compared to the same period in the previous year and a
decrease in gas sales volumes of 13.1%. Despite the volume decline, customer
growth was approximately 2%, which is consistent with historical levels. The
Company purchases natural gas in the open market and resells it at cost to its
distribution customers. As a result, increases or decreases in gas revenues
driven by gas costs do not impact the Company's gross margin or earnings.
The following table shows gas revenues by customer and average customers:
Gas Revenues
Three Months Ended
June 30,
2002 2001
------------ ------------
(In thousands)
Residential................ $25,618 $44,802
Commercial................. 8,185 12,881
Industrial................. 415 12,381
Transportation*............ 5,134 6,411
Other...................... 5,086 10,609
------------ ------------
$ 44,438 $87,084
============ ============
Average customers.......... 444,000 435,000
============ ============
36
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Three Months Ended
June 30,
2002 2001
------------ ------------
Residential................... 3,041 3,557
Commercial.................... 1,537 1,466
Industrial.................... 125 1,540
Transportation*............... 14,076 15,223
Other......................... 1,113 1,112
------------ ------------
19,892 22,898
============ ============
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
decreased $3.8 million or 13.0%. This decrease is due mainly to lower
consumption of gas for electric generation and a decrease in residential and
commercial gas sales volumes due to warmer weather conditions. The Company
currently believes that gas assets are not earning an adequate level of return.
As a result, the Company anticipates filing a request for additional rate relief
by year end.
Total non-fuel operating expense decreased $1.3 million or 4.8%.
Administrative and other costs increased $0.9 million or 6.6% for the period
primarily due to higher administrative costs allocated from Corporate. The
increase in the Corporate allocation was partially offset by the absence in 2002
of 2001 consulting expenses related to the analysis of a natural gas line
disruption and a decrease in bad debt expense resulting from improved collection
levels. Income taxes, which include taxes for interest charges, decreased $1.9
million, due to the decline in pre-tax income.
(Intentionally left blank)
37
Generation and Trading Operations
The table below sets forth the operating results for the Generation and
Trading business segment.
Generation and Trading
Three Months Ended June 30,
--------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers.......................... $ 80,194 $441,362 $(361,168)
Intersegment revenues....................... 86,012 83,396 2,616
-------------- --------------- ---------------
Total revenues.............................. 166,206 524,758 (358,552)
-------------- --------------- ---------------
Cost of energy sold........................... 102,750 374,844 (272,094)
Intersegment purchases........................ 647 177 470
-------------- --------------- ---------------
Total cost of energy........................ 103,397 375,021 (271,624)
-------------- --------------- ---------------
Gross margin.................................. 62,809 149,737 (86,928)
-------------- --------------- ---------------
Administrative and other...................... 9,960 8,293 1,667
Energy production costs....................... 33,703 37,304 (3,601)
Depreciation and amortization................. 10,573 10,521 52
Transmission and distribution costs........... 50 100 (50)
Taxes other than income taxes................. 2,796 2,322 474
Income taxes.................................. 890 32,503 (31,613)
-------------- --------------- ---------------
Total non-fuel operating expenses........... 57,972 91,043 (33,071)
-------------- --------------- ---------------
Operating income.............................. $ 4,837 $ 58,694 $ (53,857)
-------------- --------------- ---------------
Operating revenues declined $358.6 million or 68.3% for the period to
$166.2 million. This decrease in wholesale electricity sales primarily reflects
the slowdown in the wholesale electric market that resulted from steep declines
in wholesale prices and trading activity as compared to the prior year. Average
prices in the second quarter were approximately $28 per MWh as opposed to $147
per MWh in the prior year quarter.
The significantly higher wholesale pricing in 2001 was driven by
increased demand in California, a lack of generating assets to serve the market,
and the impact of warm weather. By contrast, 2002 has seen relatively mild
weather in the West, an abundance of low cost hydropower and weak economic
conditions in the region.
Trading volume declines reflect the reduction in trading partners in the
wholesale market caused by bankruptcy of certain counterparties, reduced credit
quality of firms in the market and firms exiting the wholesale trading market.
There are also significant unresolved political and regulatory issues that had a
dampening effect on activity in the marketplace. As a result, the Company's spot
market and short-term sales have declined significantly. The Company delivered
wholesale (bulk) power of 2.4 million MWh of electricity for the three months
ended June 30, 2002, compared to 3.2 million MWh for the same period in 2001.
38
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
Three Months Ended
June 30,
2002 2001
--------------- -------------
(In thousands)
Intersegment sales........... $ 86,012 $ 83,396
Long-term contract........... 10,562 16,981
Trading*..................... 64,398 424,381
Other........................ 5,234 -
--------------- -------------
$ 166,206 $ 524,758
=============== =============
*Includes mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Three Months Ended
June 30,
2002 2001
--------------- -------------
Intersegment sales........... 1,825,697 1,771,214
Long-term contract........... 227,000 368,894
Trading...................... 2,202,453 2,782,462
--------------- -------------
4,255,150 4,922,570
=============== =============
The gross margin, or operating revenues minus cost of energy sold,
decreased $86.9 million or 58.1%. Lower margins were created primarily by weak
pricing, less price volatility and decreased trading activity. Margins were also
impacted by higher coal costs at San Juan Generating Station ("SJGS"). The
Company's previously announced transition to an underground mine for the supply
of coal at SJGS was delayed, necessitating the continuation of the more
expensive surface mine operation. These lower margins were partially offset by a
favorable change in the mark-to-market position of the trading portfolio of
$33.9 million period-over-period ($6.6 million gain in 2002 versus a $27.3
million loss in 2001). A portion of the gain in 2002 represents the reversal of
previously recognized mark-to-market losses.
Non-fuel operating expenses decreased $33.1 million or 36.3%.
Administrative and other costs increased $1.7 million or 20.1% due to higher
administrative costs allocated from Corporate. Energy production costs decreased
$3.6 million or 9.7% for the period primarily due to higher maintenance costs in
2001 at SJGS as a result of an outage. Taxes other than income increased $0.5
million or 20.4% reflecting adjustments recorded in the prior year for favorable
audit outcomes by certain tax authorities. Income taxes, which include taxes for
interest charges, decreased $31.6 million or 97.3%, due to the decline in
pre-tax income.
39
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, increased $4.7 million for
the period to $24.7 million. This increase was primarily due to higher labor
resulting from a transfer of employees from operations to Corporate, higher
legal and environmental costs due to increased business exposures and outside
services related to debt refinancing activities. These increases were partially
offset by decreased retirement costs due to higher expected returns on plan
assets and a $23.5 million contribution to its plans in January 2002. In
addition, the Company had lower bonus expense resulting from lower earnings
projections.
Other Non-Operating
Other income decreased $3.0 million or 22.0% due to lower
period-over-period returns on investments reflecting current financial market
conditions.
Other deductions decreased $34.7 million or 97.2% primarily due to
charges in 2001 that did not recur in 2002. In 2001, the Company recognized
charges for the write-off of non-recoverable coal mine decommissioning costs,
made a contribution to the PNM Foundation, the write-off of an Avistar
investment and certain costs related to the Company's now terminated acquisition
of Western Resources' electric utility operations.
Income Taxes
The Company's consolidated income tax expense was $5.6 million for the
three months ended June 30, 2002, compared to $20.9 million for the three months
ended June 30, 2001. The impact of lower earnings in 2002 contributed to the
difference. The Company's effective income tax rates for the three months ended
June 30, 2002 and 2001 were 33.31% and 29.68%, respectively. Included in the
Company's 2001 taxable income were certain non-deductible costs related to the
Company's now terminated acquisition of Western Resources' electric utility
operations. In addition, the Company determined that $6.6 million of allowances
taken against certain income tax related regulatory assets were no longer
required due to changes in the evaluation of its regulatory strategy in light of
the holding company filing in May 2001. In 2000, when the allowance was
established, management believed these income tax related regulatory assets
would not be recoverable based on the probable regulatory outcome of industry
restructuring in New Mexico. Currently, management fully expects to recover
these costs in future rate cases, a situation that was not possible prior to the
delay of open access in New Mexico. Excluding these costs, the Company's
effective tax rate was 38.8% in 2001. The decrease in the effective rate was
primarily due to adjustments to the Company's prior year tax returns for certain
research and development credits related to generating plant additions.
40
RESULTS OF OPERATIONS
Six Months Ended June 30, 2002
Compared to Six Months Ended June 30, 2001
Consolidated
The Company's net earnings available to common shareholders for the six
months ended June 30, 2002 were $35.8 million, a 68.3% decrease in net earnings
from $112.9 million in 2001. This decrease primarily reflects the slowdown in
the wholesale electric market, where both prices and trading activity were
significantly lower than the prior year period. Despite the slow-down in the
wholesale electricity market, PNM's electric utility operations recorded
operating income growth of 2.5%. This growth came from a combination of load
growth and cost savings, demonstrating the balance the regulated utility
provides in the Company's "merchant utility" strategy.
Earnings in 2001 were affected by certain non-recurring charges. These
special items are detailed in the individual business segment discussions below.
The following table enumerates these non-recurring charges and shows their
effect on diluted earnings per share, in thousands, except per share amounts.
Six Months Ended
June 30,
------------------------------------------------------------
2002 2001
---------------------------- ------------------------------
EPS EPS
Earnings (Diluted) Earnings (Diluted)
-------------- ------------- --------------- --------------
(Income)/Expense
Net Earnings Available for Common
Shareholders................................ $ 35,813 $ 0.90 $ 112,856 $ 2.84
-------------- ------------- --------------- --------------
Adjustment for Special Gains and Charges
(net of income tax effects):
Contribution to PNM Foundation............... - - (3,021) (0.07)
Write-off of non-recoverable coal mine
decommissioning costs..................... - - (7,840) (0.20)
Write-off of an Avistar investment........... - - (5,387) (0.14)
Western Resources acquisition costs.......... - - (2,781) (0.07)
-------------- ------------- -------------- --------------
Total...................................... - - (19,029) (0.48)
-------------- ------------- -------------- --------------
Net Earnings Available For Common-
Shareholders Excluding Special Gains
and Charges................................. $ 35,813 $ 0.90 $ 131,885 $ 3.32
============== ============= ============== ==============
To adjust reported net earnings and diluted earnings per share to exclude
the non-recurring charges, such charges, net of income tax benefit, are added
back to reported net earnings under GAAP.
41
The following discussion is based on the financial information presented
in the Consolidated Financial Statements - Segment Information note in the Notes
to the Consolidated Financial Statements.
Utility Operations
Electric
The table below sets forth the operating results for the Electric
business segment.
Electric
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers..................... $275,565 $270,714 $ 4,851
Intersegment revenues.................. 354 354 -
-------------- --------------- ---------------
Total revenues......................... 275,919 271,068 4,851
-------------- --------------- ---------------
Cost of energy sold...................... 2,212 2,812 (600)
Intersegment purchases................... 167,962 164,313 3,649
-------------- --------------- ---------------
Total cost of energy................... 170,174 167,125 3,049
-------------- --------------- ---------------
Gross margin............................. 105,745 103,943 1,802
-------------- --------------- ---------------
Administrative and other................. 25,148 24,941 207
Depreciation and amortization............ 16,901 16,091 810
Transmission and distribution costs...... 17,317 16,441 876
Taxes other than income taxes............ 6,378 5,660 718
Income taxes............................. 11,254 12,770 (1,516)
-------------- --------------- ---------------
Total non-fuel operating expenses...... 76,998 75,903 1,095
-------------- --------------- ---------------
Operating income......................... $ 28,747 $ 28,040 $ 707
-------------- --------------- ---------------
Operating revenues increased $4.9 million or 1.8% for the period to
$275.9 million. Retail electricity delivery grew 2.2% to 3.6 million MWh in 2002
compared to 3.5 million MWh delivered in the prior year period, resulting in
increased revenues of $4.8 million year-over-year. This volume increase was the
result of a weather-driven increase in consumption and continued load growth of
2.2%. Period over period, customer growth was 2%.
(Intentionally left blank)
42
The following table shows electric revenues by customer class and average
customers:
Electric Revenues
Six Months Ended
June 30,
2002 2001
------------- -------------
(In thousands)
Residential................ $96,418 $92,843
Commercial................. 117,582 114,950
Industrial................. 40,420 40,325
Other...................... 21,499 22,950
------------- -------------
$275,919 $271,068
============= =============
Average customers 383,000 376,000
============= =============
The following table shows electric sales by customer class:
Electric Sales
(Megawatt hours)
Six Months Ended
June 30,
2002 2001
------------- -------------
Residential............... 1,123,413 1,083,085
Commercial................ 1,534,477 1,515,027
Industrial................ 797,917 784,967
Other..................... 109,365 106,700
------------- -------------
3,565,172 3,489,779
============= =============
The gross margin, or operating revenues minus cost of energy sold,
increased $1.8 million or 1.7%, which reflects the increased energy sales.
Electric exclusively purchases power from Generation and Trading at Company
developed prices, which are not based on market rates. These intercompany
revenues and expenses are eliminated in the consolidated results.
Total non-fuel operating expenses increased $1.1 million or 1.4%.
Administrative and other costs were flat for the period. Lower bad debt expense
as a result of collection improvements and the absence of the bankruptcy of a
significant customer in 2001 were offset by higher administrative cost allocated
from Corporate. Depreciation and amortization increased $0.8 million or 5.0% for
the period due to a higher depreciable plant base. Transmission and distribution
costs increased $0.9 million or 5.3% primarily due to an increase in overhead
line maintenance focused on improving overall system reliability. Taxes other
than income increased $0.7 million or 12.7% primarily reflecting the absence of
favorable audit outcomes by certain tax authorities in 2001. Income taxes, which
include taxes associated with interest charges, decreased $1.5 million or 11.9%
due to lower pre-tax income.
43
Gas
The table below sets forth the operating results for the Gas business
segment.
Gas
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers............................. $153,169 $279,020 $(125,851)
Intersegment revenues.......................... 470 - 470
-------------- --------------- ---------------
Total revenues................................. 153,639 279,020 (125,381)
-------------- --------------- ---------------
Total cost of energy........................... 83,671 206,217 (122,546)
-------------- --------------- ---------------
Gross margin..................................... 69,968 72,803 (2,835)
-------------- --------------- ---------------
Administrative and other......................... 25,657 27,527 (1,870)
Depreciation and amortization.................... 10,388 10,623 (235)
Transmission and distribution costs.............. 14,524 13,703 821
Taxes other than income taxes.................... 4,086 3,652 434
Income taxes..................................... 3,436 4,495 (1,059)
-------------- --------------- ---------------
Total non-fuel operating expenses.............. 58,091 60,000 (1,909)
-------------- --------------- ---------------
Operating income................................. $ 11,877 $ 12,803 $ (926)
-------------- --------------- ---------------
Operating revenues decreased $125.4 million or 44.9% for the period to
$153.6 million, primarily as the result of lower natural gas prices during the
second quarter of 2002 as compared to the same period in the previous year and a
decrease in gas sales volumes of 8.5%. Despite the volume decline, customer
growth was approximately 2%. The Company purchases natural gas in the open
market and resells it at cost to its distribution customers. As a result,
increases or decreases in gas revenues driven by gas costs do not impact the
Company's gross margin or earnings.
The following table shows gas revenues by customer and average customers:
Gas Revenues
Six Months Ended
June 30,
2002 2001
-------------- -------------
(In thousands)
Residential............... $97,724 $166,396
Commercial................ 30,590 49,675
Industrial................ 1,064 25,918
Transportation*........... 8,745 10,413
Other..................... 15,516 26,618
-------------- -------------
$153,639 $279,020
============== =============
Average customers......... 444,000 435,000
============== =============
44
The following table shows gas throughput by customer class:
Gas Throughput
(Thousands of decatherms)
Six Months Ended
June 30,
2002 2001
-------------- -------------
Residential 16,500 16,020
Commercial............... 6,564 5,691
Industrial............... 296 3,520
Transportation*.......... 21,473 24,401
Other.................... 3,104 2,777
-------------- -------------
47,937 52,409
============== =============
*Customer-owned gas.
The gross margin, or operating revenues minus cost of energy sold,
decreased $2.8 million or 3.9%. This decrease is due mainly to lower consumption
of gas for electric generation partially offset by a 2% growth in customer base.
Total non-fuel operating expenses decreased $1.9 million or 3.2%.
Administrative and other costs decreased $1.9 million or 6.8%. This decrease is
primarily due to a lower bad debt expense as a result of losses from a
bankruptcy of a significant customer in 2001. This cost improvement was largely
offset by higher allocated Corporate administrative costs. Transmission and
distribution costs increased $0.8 million or 6.0% primarily due to lower capital
activity in 2002. Income taxes, which include income taxes for interest charges,
decreased $1.1 million or 23.6% due to lower pre-tax income.
(Intentionally left blank)
45
Generation and Trading Operations
The table below sets forth the operating results for the Generation and
Trading business segment.
Generation and Trading
Six Months Ended June 30,
-------------------------------
2002 2001 Variance
-------------- --------------- ---------------
(In thousands)
Operating revenues:
External customers............................. $148,914 $851,610 $(702,696)
Intersegment revenues.......................... 167,962 164,313 3,649
-------------- --------------- ---------------
Total revenues................................. 316,876 1,015,923 (699,047)
-------------- --------------- ---------------
Cost of energy sold.............................. 191,917 721,910 (529,993)
Intersegment purchases........................... 824 354 470
-------------- --------------- ---------------
Total cost of energy........................... 192,741 722,264 (529,523)
-------------- --------------- ---------------
Gross margin..................................... 124,135 293,659 (169,524)
-------------- --------------- ---------------
Administrative and other......................... 16,218 14,778 1,440
Energy production costs.......................... 67,914 71,588 (3,674)
Depreciation and amortization.................... 21,480 21,416 64
Transmission and distribution costs.............. 145 213 (68)
Taxes other than income taxes.................... 5,616 4,243 1,373
Income taxes..................................... 2,344 64,621 (62,277)
-------------- --------------- ---------------
Total non-fuel operating expenses.............. 113,717 176,859 (63,142)
-------------- --------------- ---------------
Operating income................................. $ 10,418 $116,800 $(106,382)
-------------- --------------- ---------------
Operating revenues declined $699.0 million or 68.8% for the period to
$316.9 million. This decrease in wholesale electricity sales primarily reflects
the slowdown in the wholesale electric market, which resulted from steep
declines in wholesale prices and trading activity as compared to the prior year
period.
The significantly higher wholesale pricing in 2001 was driven by
increased demand in California, a lack of generating assets to serve the market,
and the impact of warm weather. By contrast, 2002 has seen relatively mild
weather in the West, an abundance of low cost hydropower and weak economic
conditions in the region. As a result, the average price realized by the Company
fell to approximately $26 per MWh in 2002 versus $139 per MWh in 2001.
Trading volume declines reflect the reduction in trading partners in the
wholesale market caused by bankruptcy, reduced credit quality of firms in the
market and firms exiting the wholesale trading market. There are also
significant unresolved political and regulatory issues that had a dampening
effect on activity in the marketplace. As a result, the Company's spot market
and short-term sales have declined significantly. The Company delivered
wholesale (bulk) power of 4.8 million MWh of electricity for the six months
ended June 30, 2002, compared to 6.3 million MWh for the same period in 2001.
Although other firms have exited the wholesale market or have had their
access to the wholesale market limited due to concerns over credit quality, the
Company remains committed to be a participant in this market place. While market
liquidity is weak, the Company will focus on long-term relationships with
smaller wholesale customers (small investor-owned utilities, municipal utilities
and co-ops). At the same time the Company will continue to monitor market
conditions.
46
This commitment to the wholesale market leaves the Company poised to
participate in the market as liquidity returns and regulatory issues are
resolved.
The following table shows revenues by customer class:
Generation and Trading Revenues By Market
Six Months Ended
June 30,
2002 2001
-------------- --------------
(In thousands)
Intersegment sales............ $ 167,962 $ 164,313
Long-term contract............ 24,899 45,795
Trading*...................... 115,874 802,432
Other......................... 8,141 3,383
-------------- --------------
$ 316,876 $1,015,923
============== ==============
*Includes mark-to-market gains/(losses).
The following table shows sales by customer class:
Generation and Trading Sales By Market
(Megawatt hours)
Six Months Ended
June 30,
2002 2001
-------------- --------------
Intersegment sales........... 3,565,172 3,489,779
Long-term contract........... 508,153 846,947
Trading...................... 4,262,695 5,462,540
-------------- --------------
8,336,020 9,799,266
============== ==============
The gross margin, or operating revenues minus cost of energy sold,
decreased $169.5 million or 57.7%. Lower margins were created primarily by weak
pricing, less price volatility and lower trading liquidity. Margins were also
impacted by higher coal costs at SJGS. The Company's previously announced
transition to an underground mine for supply of coal at SJGS was delayed,
necessitating the continuation of the more expensive surface mine operation.
These lower margins were partially offset by a favorable change in the
mark-to-market position of the trading portfolio of $42.3 million
period-over-period ($16.1 million gain in 2002 versus $26.2 million loss in
2001). A portion of the gain in 2002 represents the reversal of previously
recognized mark-to-market losses.
Total non-fuel operating expenses decreased $63.1 million or 35.7%.
Administrative and other costs increased $1.4 million or 9.7% for the period.
This increase is primarily due to higher corporate allocations and an adjustment
to prior year SJGS participant billings (the Company is the operator of SJGS and
47
shares costs with other owners). These cost increases were partially offset by
lower costs resulting from increased capital activity for generation expansion.
Energy production costs also decreased $3.7 million or 5.1% for the period
reflecting the benefits of the acceleration into 2001 of a planned outage at
SJGS offset by a planned and unplanned outage at the Company's Four Corners
facility. Taxes other than income increased $1.4 million or 32.4% reflecting
adjustments recorded in the prior year for favorable audit outcomes by certain
tax authorities. Income taxes, which include income taxes for interest charges,
decreased $62.3 million or 96.4% due to a decline in pre-tax income.
Corporate
Corporate administrative and general costs, which represent costs that
are driven exclusively by corporate-level activities, decreased $4.7 million for
the period to $41.6 million. This decrease was primarily due to lower retiree
benefits expense and lower bonus expense in the current year resulting from
lower earnings projections.
Other Non-Operating
Other income decreased by $4.2 million or 15.5% reflecting lower
year-over-year returns on investments reflecting market conditions.
Other deductions decreased $43.8 million or 97.9% primarily due to
charges in 2001 that did not recur in 2002. In 2001, the Company recognized
charges for the write-off of non-recoverable coal mine decommissioning costs, a
contribution to the PNM Foundation, the write-off of an Avistar investment, and
certain costs related to the Company's now terminated acquisition of Western
Resources' electric utility operations.
Income Taxes
The Company's consolidated income tax expense was $19.8 million for the
six months ended June 30, 2002, compared to $63.6 million for the six months
ended June 30, 2001. The impact of lower earnings in 2002 contributed to the
difference. The Company's effective income tax rates for the six months ended
June 30, 2002 and 2001 were 35.39% and 35.97%, respectively. Included in the
Company's 2001 taxable income were certain non-deductible costs related to the
Company's now terminated acquisition of Western Resources' electric utility
operations. In addition, the Company determined that $6.6 million of allowances
taken against certain income tax related regulatory assets were no longer
required due to changes in the evaluation of its regulatory strategy in light of
the holding company filing in May 2001. In 2000, where the allowance was
established, management believed these income tax related regulatory assets
would not be recoverable based on the probable regulatory outcome of industry
restructuring in New Mexico. Currently, management fully expects to recover
these costs in future rate cases, a situation that was not possible prior to the
delay of open access in New Mexico. Excluding these costs, the Company's
effective tax rate was 38.9% in 2001. The decrease in the effective rate was
primarily due to adjustments to the Company's prior year tax returns for certain
research and development credits.
FUTURE EXPECTATIONS
Continued weakness in the wholesale power market has caused the Company
to reduce its 2002 earnings estimate. On July 9, 2002, the Company announced
that it expects 2002 earnings for the twelve months to be in the range of $1.90
to $2.10. Although the Company's electric utility continues to perform well, the
48
depressed level of wholesale prices in the West, coupled with the significantly
decreased trading activity in that market, has severely limited the potential of
Generation and Trading Operations.
Several factors, including an abundance of available hydropower from the
Pacific Northwest, cooler weather through May and June, low natural gas prices,
the number of new generating plants coming on line, and the lingering slowdown
in the regional economy have all contributed to keeping power prices down in
2002. Additionally, fewer credit-worthy counterparties and political and
regulatory uncertainty regarding the Western marketplace have significantly
reduced market liquidity and trading volume as some companies have curtailed
their activity or exited the business altogether. These factors resulted in a
25% reduction in wholesale sales for the Company compared to the first half of
2001.
Other contributing factors include increased coal costs and lower
earnings in the gas utility business as a result of a mild spring.
To preserve the Company's strong financial position, management intends
to control expenses and limit capital expenditures. Construction expenditures in
2002, originally budgeted at $391 million, have been reduced by $111 million to
$280 million for the year. Planned construction expenditures through 2003 have
been reduced in total by over $400 million.
Although the current environment has led the Company to scale back its
expansion plans, the Company will continue to operate in the wholesale market.
Expansion of the Company's generating portfolio will depend upon acquiring
favorably priced assets at strategic locations and securing long-term
commitments for the purchase of power from those new plants.
This discussion of future expectations is forward looking information
within the meaning of Section 21E of the Securities Exchange Act of 1934. The
achievement of expected results is dependent upon the assumptions described in
the preceding discussion, and is qualified in its entirety by the Private
Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding
Forward Looking Statements" below) - and the factors described within the
disclosure that could cause the Company's actual financial results to differ
materially from the expected results enumerated above.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2002, the Company had cash and short-term investments of
$154.5 million compared to $71.2 million in cash and short-term investments at
December 31, 2001. Certain long-term investments have been reclassified as
short-term to reflect the Company's liquidity needs to fund certain construction
projects in 2002.
Cash provided from operating activities in the six months ended June 30,
2002 was $55.8 million compared to cash provided by operating activities of
$257.5 million for the six months ended June 30, 2001. This decrease was
primarily the result of current wholesale market conditions. Also contributing
to the decrease was the Company's $23.5 million contribution to its pension and
postretirement benefit plans. In addition, the Company did not make its first
quarter 2001 estimated federal income tax payment of $32.0 million until January
2002 because of an extension granted by the IRS to taxpayers in several counties
in New Mexico as a result of wildfires in 2000. This out-of-period income tax
payment reduced operating cash flows below normal levels.
49
Cash used for investing activities was $80.2 million in 2002 compared to
$113.0 million in 2001. Cash used for investing activities includes construction
expenditures for new generating plants of $82.6 million in 2002, which did not
occur in 2001. These cash outflows were partially offset by the redemption of
short-term investments of $45.0 million. Expenditures in 2001 reflect the
acquisition of certain transmission assets and other related investing
activities of $13.9 million.
Cash generated by financing activities was $44.6 million in 2002 compared
to $18.9 million of cash used in 2001. Financing activities in 2002 were
primarily short-term borrowings of $65 million for liquidity reasons, partially
offset by cash payments for dividend requirements. The use of cash in 2001
primarily reflects cash payments for dividend requirements.
Pension and Other Postretirement Benefits
In 2001, the investment market experienced significant declines
reflecting the events in the financial markets after September 11, 2001. As a
result, the Company had lowered its expected rate of return on its retiree
benefit plans assets. By year end 2001, markets had recovered significantly. As
a result, in 2002 the Company adjusted its return assumption to its historic
view of a 9% long-term rate of return. In addition, in January 2002, the Company
made an aggregate contribution of $23.5 million to fund the pension and other
postretirement benefit plans. The effect of the change in expected rate of
return and additional cash contribution has a decrease in pension and other
benefits expense for the six months ended June 30, 2002.
Capital Requirements
Total capital requirements include construction expenditures as well as
other major capital requirements and cash dividend requirements for both common
and preferred stock. The main focus of the Company's construction program is
upgrading generation systems and expanding its wholesale generation
capabilities; upgrading and expanding the electric and gas transmission and
distribution systems; and purchasing nuclear fuel. To preserve a strong
financial position, the Company plans to reduce its capital expenditures for
planned generation expansion. Projections for total capital requirements for
2002 are $298 million and projections for construction expenditures for 2002,
originally predicted to be $391 million, have been reduced by $111 million to
$280 million for the year. For 2002-2006 projections, total capital requirements
are $1.5 billion and construction expenditures are $1.4 billion, including the
combustion turbines discussed below. These estimates are under continuing review
and subject to on-going adjustment.
PNM has committed to purchase five combustion turbines for a total cost
of $151.3 million. The turbines are for planned power generation plants with an
estimated cost of construction of approximately $370 million over the next five
years depending on market conditions. PNM has expended $193 million as of June
30, 2002 of which $123.0 million was for equipment purchases. In November 2001,
PNM broke ground to build Afton Generating Station, a 135 MW simple cycle gas
turbine plant in Southern New Mexico. In February 2002, PNM broke ground to
build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired
generating plant in Southern New Mexico. On June 27, 2002, Lordsburg became
fully operational and will serve the wholesale power market. Construction
contracts have not been finalized on the remaining planned construction. These
plants are part of the Company's ongoing competitive strategy of increasing
generation capacity over time. These plants are not anticipated to be added to
rate base.
50
The Company's construction expenditures for 2001 were entirely funded
through cash generated from operations. In the first six months of 2002, the
Company utilized cash generated from operations, cash on hand, as well as its
liquidity arrangements to cover its construction commitments. The Company
anticipates that internal cash generation and current debt capacity will be
sufficient to meet all its capital requirements for the years 2002 through 2006.
To cover the difference in the amounts and timing of cash generation and cash
requirements, the Company intends to use short-term borrowings under its current
and future liquidity arrangements.
Liquidity
In July 2002, PNM had $200 million of available liquidity arrangements,
consisting of $150 million from an unsecured revolving credit facility ("Credit
Facility"), $30 million in local lines of credit and $20 million from a
reciprocal borrowing agreement with the Holding Company. The Credit Facility
will expire in March 2003. There were $100 million in borrowings against the
credit facility as of August 1, 2002. In addition, the Holding Company has a $20
million reciprocal borrowing agreement with PNM and $25 million in local lines
of credit.
The Company's ability, if required, to access the capital markets at a
reasonable cost and to provide for other capital needs is largely dependent upon
its ability to earn a fair return on equity, results of operations, credit
ratings, regulatory approvals and financial and wholesale market conditions.
Financing flexibility is enhanced by providing a high percentage of total
capital requirements from internal sources and having the ability, if necessary,
to issue long-term securities, and to obtain short-term credit.
PNM's credit outlook is considered stable by Moody's Investor Services
("Moody's") and Standard and Poor's ("S&P") and positive by Fitch Ratings
("Fitch"). Previously, in connection with PNM's announcement of its agreement to
acquire Western Resources' electric utility operations, S&P, Moody's and Fitch
placed PNM's securities ratings on negative credit watch pending review of the
transaction. As a result of events which led the Company to conclude the
acquisition could not be accomplished, ultimately leading the Company to
terminate the transaction in January 2002, S&P, Moody's and Fitch removed the
Company from negative credit watch. The Company is committed to maintaining its
investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and
its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its
preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution
control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured
debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution
control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM's
preferred stock "BB-." Investors are cautioned that a security rating is not a
recommendation to buy, sell or hold securities, that it may be subject to
revision or withdrawal at any time by the assigning rating organization, and
that each rating should be evaluated independently of any other rating.
51
Long-term Obligations and Commitments
The following table shows PNM's long-term debt and operating leases as of
June 30, 2002. As of June 30, 2002, PNM Resources, Inc. and Subsidiaries have no
long-term obligations except those acquired through consolidation with PNM.
Payments Due
-----------------------------------------------------------------------
(In thousands)
Less than
Contractual 1 year 2-3 years 4-5 years After 5
Obligations Total years
------------- ----------- ----------- ----------- -------------
Long-Term Debt.................... $ 953,912 $ - $ - $268,420 $ 685,492
Operating Leases.................. 516,906 32,572 67,022 70,764 346,548
------------- ----------- ----------- ----------- -------------
Total Contractual Cash
Obligations.................... $1,470,818 $32,572 $67,022 $339,184 $1,032,040
============= =========== =========== =========== =============
PNM leases interests in Units 1 and 2 of PVNGS, certain transmission
facilities, office buildings and other equipment under operating leases. The
lease expense for PVNGS is $66.3 million per year over base lease terms expiring
in 2015 and 2016. In 1998, PNM established PVNGS Capital Trust ("Capital Trust")
for the purpose of acquiring all the debt underlying the PVNGS leases. PNM
consolidates Capital Trust in its consolidated financial statements. The
purchase was funded with the proceeds from the issuance of $435 million of SUNs,
which were loaned to Capital Trust. Capital Trust then acquired and now holds
the debt component of the PVNGS leases. For legal and regulatory reasons, the
PVNGS lease payment continues to be recorded and paid gross with the debt
component of the payment returned to PNM via Capital Trust. As a result, the net
cash outflows for the PVNGS lease payment were $12.4 million as of 2002. The
table above reflects the net lease payment.
PNM's other significant operating lease obligations include the Eastern
Interconnect Project ("EIP"), a transmission line with annual lease payments of
$7.3 million, and a power purchase agreement for the entire output of Delta
Person Generating Station ("Delta"), a gas-fired generating plant in
Albuquerque, New Mexico with imputed annual lease payments of $6.0 million.
The Company's off-balance sheet obligations are limited to PNM's
operating leases and certain financial instruments related to the purchase and
sale of energy (see below). The present value of PNM's operating lease
obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $224 million as
of June 30, 2002.
PNM has entered various long-term power purchase agreements obligating it
to make aggregate fixed payments of $27.7 million plus the cost of production
and a return. These contracts expire December 2006 through July 2010. In
addition, PNM is obligated to sell electricity for $194.1 million in fixed
payments plus the cost of production and a return. These contracts expire
December 2003 through June 2010. PNM's trading portfolio as of June 30, 2002
included open contract positions to buy $33.3 million of electricity and to sell
$51.1 million of electricity. In addition, PNM had open forward positions
classified as normal sales of electricity under the derivative accounting rules
of $18.3 million and normal purchases of electricity of $52.3 million.
52
PNM has a coal supply contract for the needs of SJGS until 2017. The
contract contemplates the delivery of approximately 103 million tons of coal
during its remaining term. The pricing is based on the cost of extraction plus a
margin.
PNM contracts for the purchase of gas to serve its retail customers.
These contracts are short-term in nature supplying the gas needs for the current
heating season and the following off-season months. The price of gas is a
pass-through, whereby the Company recovers 100% of its cost of gas.
Contingent Provisions of Certain Obligations
The Holding Company and PNM have a number of debt obligations and other
contractual commitments that contain contingent provisions. Some of these, if
triggered, could affect the liquidity of the Company. The Holding Company and/or
PNM could be required to provide security, immediately pay outstanding
obligations or be prevented from drawing on unused capacity under certain credit
agreements, if the contingent requirements were to be triggered. The most
significant consequences resulting from these contingent requirements are
detailed in the discussion below.
PNM's master purchase agreement for the procurement of gas for its retail
customers contains a contingent requirement that could require PNM to provide
security for its gas purchase obligations if the seller were to reasonably
believe that PNM was unable to fulfill its payment obligations under the
agreement.
The master agreement for the sale of electricity in the Western System
Power Pool ("WSPP") contains a contingent requirement that could require PNM to
provide security if its' debt were to fall below the investment grade rating.
The WSPP agreement also contains a contingent requirement, commonly called a
material adverse change ("MAC") provision, which could require PNM to provide
security if a material adverse change in its financial condition or operations
were to occur.
PNM's committed Credit Facility contains a MAC provision which if
triggered could prevent PNM from drawing on its unused capacity under the Credit
Facility. In addition, the Credit Facility contains a contingent requirement
that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's
debt-to-capital ratio were to exceed 70%, PNM could be required to repay all
borrowings under the Credit Facility, be prevented from drawing on the unused
capacity under the Credit Facility, and be required to provide security for all
outstanding letters of credit issued under the Credit Facility. At June 30,
2002, the Company had $8.5 million of letters of credit outstanding.
If a contingent requirement were to be triggered under the Credit
Facility resulting in an acceleration of the outstanding loans under the Credit
Facility, a cross-default provision in the PVNGS leases could occur if the
accelerated amount is not paid. If a cross-default provision is triggered, the
lessors have the ability to accelerate their rights under the leases, including
acceleration of all future lease payments.
53
Planned Financing Activities
PNM has $268.4 million of long-term debt that matures in August 2005. All
other long-term debt matures in 2016 or later. The Company could enter into
other long-term financings for the purpose of strengthening its balance sheet,
funding growth and reducing its cost of capital. The Company continues to
evaluate its investment and debt retirement options to optimize its financing
strategy and earnings potential. No additional first mortgage bonds may be
issued under PNM's mortgage. The amount of SUNs that may be issued is not
limited by the SUNs indenture. However, debt-to-capital requirements in certain
of PNM's financial instruments would ultimately limit the amount of SUNs PNM
would issue.
PNM currently has $182.0 million of tax-exempt bonds outstanding that are
callable at a premium in December 2002 and August 2003. PNM intends to refinance
these bonds assuming the interest rate of the refinancing does not exceed the
current interest rate of the bonds and has hedged the entire planned
refinancing. In order to take advantage of current low interest rates, PNM
entered into two forward starting interest rate swaps in November and December
2001 and three additional contracts during the first quarter of 2002. PNM
designated these swaps as cash flow hedges. The hedged risks associated with
these instruments are the changes in cash flows related to general moves in
interest rates expected for the refinancing. The swaps effectively cap the
interest rate on the refinancing to 4.9% plus an adjustment for PNM's and the
industry's credit rating. PNM's assessment of hedge effectiveness is based on
changes in the hedge interest rates. The derivative accounting rules, as
amended, provide that the effective portion of the gain or loss on a derivative
instrument designated and qualifying as a cash flow hedging instrument be
reported as a component of other comprehensive income and be reclassified into
earnings in the same period or periods during which the hedged forecasted
transactions affect earnings. Any hedge ineffectiveness is required to be
presented in current earnings. There was no material hedge ineffectiveness in
the six months ended June 30, 2002.
A forward starting swap does not require any upfront premium and captures
changes in the corporate credit component of an investment grade company's
interest rate as well as the underlying Treasury benchmark. The five forward
interest rate starting swaps have termination dates and notional amounts as
follows: one with a termination date of September 17, 2002 for a notional amount
of $46.0 million and four with a termination date of May 15, 2003 for a combined
notional amount of $136.0 million. There were no fees on the transaction, as
they are imbedded in the rates, and the transaction is cash settled on the
mandatory unwind date (strike date), corresponding to the refinancing date of
the underlying debt. The settlement will be capitalized as a cost of issuance
and amortized over the life of the debt as a yield adjustment.
Dividends
The Company's Board of Directors regularly reviews the Company's dividend
policy. The declaration of common dividends is dependent upon a number of
factors including the ability of the Company's subsidiaries to pay dividends.
Currently, PNM is the Holding Company's primary source of dividends. As part of
the order approving the formation of the Holding Company, the PRC placed certain
restrictions on the ability of PNM to pay dividends to the Holding Company. PNM
cannot pay dividends, which cause its debt rating to go below investment grade;
and PNM cannot pay dividends in any year, as determined on a rolling
four-quarter basis, in excess of net earnings without prior PRC approval.
Additionally, PNM has various financial covenants, which limit the transfer of
assets, through dividends or other means.
54
In addition, the ability of the Company to declare dividends is dependent
upon the extent to which cash flows will support dividends, the availability of
retained earnings, its financial circumstances and performance, the PRC's
decisions in various regulatory cases currently pending and which may be
docketed in the future, the effect of deregulating generation markets and market
economic conditions generally. The ability to recover stranded costs in
deregulation (as amended), conditions imposed on holding company formation,
future growth plans and the related capital requirements and standard business
considerations may also affect the Company's ability to pay dividends.
Consistent with the PRC's holding company order, PNM paid dividends of
$127.0 million to the Holding Company on December 31, 2001. On March 4, 2002,
the PNM Board of Directors declared a dividend of $5.5 million, which was paid
on March 19, 2002. On June 10, 2002, the PNM Board of Directors declared a
dividend of $24.7 million, which was paid on June 28, 2002.
On February 19, 2002, the Company's Board of Directors approved a 10
percent increase in the common stock dividend. The increase raises the quarterly
dividend to $0.22 per share, for an indicated annual dividend of $0.88 per
share. The Company's Board of Directors approved a policy for future dividend
increases in the range of 8 to 10 percent annually, targeting a payout of
between 50 to 60 percent of regulated earnings. The Company believes that this
target is consistent with the Company's expectation of future operating cash
flows and the cash needs of its planned increase in generating capacity.
Capital Structure
The Company's capitalization, including current maturities of long-term
debt, at June 30, 2002 and December 31, 2001 is shown below:
June 30, December 31,
2002 2001
--------------- --------------
Common Equity...................... 51.4% 50.8%
Preferred Stock.................... 0.6 0.6
Long-term Debt..................... 48.0 48.6
--------------- --------------
Total Capitalization*........... 100.0% 100.0%
=============== ==============
* Total capitalization does not include as debt the present value of
PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and
the Delta PPA, which was $224 million as of June 30, 2002 and $225
million as of December 31, 2001.
OTHER ISSUES FACING THE COMPANY
RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY
In April 1999, New Mexico's Electric Utility Industry Restructuring Act
of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act
opens the state's electric power market to customer choice. In March 2001,
amendments to the Restructuring Act were passed which delay the original
implementation dates by approximately five years, including the requirement for
55
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets. In addition, the PRC will have the
authority to delay implementation for another year under certain circumstances.
The Restructuring Act, as amended, will give schools, residential and small
business customers the opportunity to choose among competing power suppliers
beginning in January 2007. Competition would be expanded to include all
customers starting in July 2007. The Company is unable to predict the form its
further restructuring will take under the delayed implementation of customer
choice. In addition, the Restructuring Act, as amended, recognizes that electric
utilities should be permitted a reasonable opportunity to recover an appropriate
amount of the costs previously incurred in providing electric service to their
customers.
The amendments to the Restructuring Act required that the PRC approve a
holding company, subject to terms and conditions in the public interest, without
corporate separation of supply service and energy-related service assets from
distribution and transmission service assets, by July 1, 2001. In addition, the
amendments allow utilities to engage in unregulated power generation business
activities until corporate separation is implemented.
On December 31, 2001, the Company implemented the holding company
structure without corporate separation of supply service and energy-related
services assets from distribution and transmission services assets. This
structure provides for a holding company whose current holdings will be PNM,
Avistar and other inactive unregulated subsidiaries. This was effected through
the share exchange between PNM shareholders and the Holding Company, PNM
Resources Inc. Avistar and most of the inactive unregulated subsidiaries became
wholly-owned subsidiaries of the Holding Company in January 2002. The transfer
of certain corporate related assets to the Holding Company also occurred in
January 2002. There are no current plans to provide the Holding Company with
significant debt financing.
The 2002 session of the New Mexico Legislature resulted in enactment of
tax measures favorable to the construction of merchant generating plants and
plants fueled by renewable resources. The new laws provide authority for all
local governments in the state to issue industrial revenue bonds for merchant
generating plants smaller than 300 MW. The bonds provide exemptions from
property taxes. Also enacted into law was a 5% investment tax credit for
merchant generating plants smaller than 300 MW; tax credits for qualified
generators using renewable resources; and an exemption from gross receipts tax
for the cost of certain wind generation equipment.
There is a growing concern in New Mexico about the use of water for
merchant power plants, due to the increased activity in building these plants in
the state, which has an arid climate. The availability of sufficient water
supplies to meet all the needs of the state, including growth, is a major issue.
An interim committee of the legislature is studying the impact of power plants
on the state's water and other natural resources, with a report to be issued for
the 2003 session. In building the Afton and Lordsburg plants, which are much
smaller than other merchant plants under construction or planned by other
generating companies, the Company has secured sufficient water rights.
On April 25, 2002, by a vote of 88-11, the U.S. Senate passed amendments
to HR 4, the "Energy Policy Act of 2002". The Senate version contains provisions
directly applicable to the electric industry, many of which were not contained
in the House version of HR 4. As adopted by the Senate, HR 4 contains provisions
56
revising FERC authority over utility mergers; provides direction to the FERC
regarding the use of market-based rates; provides for possible refunds dating
from the date of a complaint rather than the current 60 day waiting period;
provides for a reliability organization to establish standards subject to FERC
oversight; requires the FERC to establish an electronic information system about
wholesales sales and transmission; extends FERC jurisdiction over large
municipal utilities, cooperatives and power marketing agencies; requires access
to transmission for intermittent generators that are exclusively solar or wind;
repeals the Public Utility Holding Company Act ("PUHCA"); provides for federal
and state access to holding company records; conditionally repeals the Public
Utility Regulatory Policy Act ("PURPA") if qualifying facilities have access to
independent, day-ahead and real-time auction based markets; requires states to
consider adopting standards for real time pricing, time of use metering and net
metering; authorizes the Federal Trade Commission ("FTC") to establish consumer
protection rules; establishes consumer advocates in the Department of Justice
("DOJ"); requires federal agencies to attempt to purchase a percentage of
electricity from renewable sources, starting at 3% increasing to 7.5%;
establishes renewable portfolio standard for investor owned utilities that
increases to 10% by 2020; establishes a voluntary registry for reporting
greenhouse gas emissions and emission reductions (which could become mandatory
for reporting emissions within 5 years); reforms nuclear decommissioning tax
provisions; provides tax relief for sale of transmission assets to an
independent transmission company; and extends protections against liability for
nuclear accidents under the Price-Anderson Act. The differences in the two
versions of HR 4 will be the subject of conference committee discussions later
this year. The Company is unable to predict what form energy legislation will
take if agreement is reached between the House and the Senate, if energy
legislation will be passed or if it will be signed by the President if passed.
Included in the debate over energy legislation are drilling in the Arctic
National Wildlife Refuge and automobile fuel efficiency requirements.
The Company along with other Southwest transmission owners formed
WestConnect RTO, LLC ("WestConnect") a for-profit transmission company and made
a filing on October 16, 2001 with the FERC. WestConnect is the only remaining
Regional Transmission Organization ("RTO") still proposing a transmission asset
owning company form of governance. However, WestConnect allows for, but does not
require a member to transfer its transmission assets. WestConnect is awaiting a
FERC order on its formation.
To remedy what FERC sees as undue discrimination in the provision of
interstate transmission services and to ensure just and reasonable rates for
sales of electric energy within and among regional power markets, the Commission
has approved a Notice of Proposed Rulemaking (NOPR) for Standard Market Design.
The proposed rule would put all transmission customers, including bundled retail
customers, under new pro forma transmission rates for new transmission service.
All transmission will be operated under Independent Transmission Providers
(including RTOs) and congestion management will be handled under locational
marginal pricing with tradable congestion revenue rights. The Company will be
making comments on the Standard Market Design NOPR along with the other
WestConnect companies and will continue to participate in the rulemaking
process. The Company is also following FERC rulemakings on Standards of Conduct
and Standardizing Generation Interconnection Agreements and Procedures and has
submitted comments or has commented in conjunction with WestConnect and Edison
Electric Institute.
57
RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT
Stranded Costs
The Restructuring Act, as amended, recognizes that electric utilities
should be permitted a reasonable opportunity to recover an appropriate amount of
the costs previously incurred in providing electric service to their customers.
These stranded costs represent all costs associated with generation-related
assets, currently in rates, in excess of the expected competitive market price
over the life of those assets and include plant decommissioning costs,
regulatory assets, and lease and lease-related costs. Utilities will be allowed
to recover no less than 50% of stranded costs through a non-bypassable charge on
all customer bills for five years after implementation of customer choice. The
PRC could authorize a utility to recover up to 100% of its stranded costs if the
PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is
necessary to maintain the financial integrity of the public utility; (iii) is
necessary to continue adequate and reliable service; and (iv) will not cause an
increase in rates to residential or small business customers during the
transition period. The Restructuring Act, as amended, also allows for the
recovery of nuclear decommissioning costs by means of a separate wires charge
over the life of the underlying generation assets (see Nuclear Regulatory
Commission Prefunding below).
The calculation of stranded costs is subject to a number of highly
sensitive assumptions, including the date of open access, appropriate discount
rates and projected market prices, among others. The Restructuring Act, as
amended, requires the Company to file a transition plan, which includes
provisions for the recovery of stranded costs, and other expenses associated
with the transition to a competitive market no later than January 1, 2005. The
Company is unable to predict the amount of stranded costs that it may seek to
recover at that time. The Company's previous proposal to recover stranded costs
under the original customer choice implementation dates would not accurately
represent the Company's expected stranded costs under the amended implementation
dates of the Restructuring Act.
Approximately $141 million of costs associated with the power supply and
energy services businesses under the Restructuring Act were established as
regulatory assets. Because of the Company's belief that recovery is probable,
these assets continue to be classified as regulatory assets, although the
Company has discontinued the use of accounting for rate regulated activities.
The amendments to the Restructuring Act provide the opportunity for amortization
of coal mine decommissioning costs currently estimated at approximately $100
million. The Company intends to seek recovery of these costs in its next rate
case filing and believes that the costs are fully recoverable. The Company
believes that any remaining portion of the regulatory assets will be fully
recovered in future rates, including through a non-bypassable wires charge.
The Company believes that the Restructuring Act, as amended, if properly
applied, provides an opportunity for recovery of a reasonable amount of stranded
costs should such costs exist at the time of separation. If regulatory orders do
not provide for a reasonable recovery, the Company is prepared to vigorously
pursue judicial remedies. The PRC will make a determination and quantification
of stranded cost recovery prior to implementation of restructuring. The
determination may have an impact on the recoverability of the related assets and
may have a material effect on the future financial results and position of the
Company.
58
Transition Cost Recovery
In addition, the Restructuring Act, as amended, authorizes utilities to
recover in full any prudent and reasonable costs incurred in implementing full
open access ("transition costs"). These transition costs are currently scheduled
to be recovered from 2007 through 2012 by means of a separate wires charge. The
PRC may extend this date by up to one year. The Company may seek to recover
transition costs already incurred in future rate cases that may occur prior to
open access. The Company is unable to predict the amount of transition costs it
may incur. To date, the Company has capitalized $24.8 million of expenditures
that meet the Restructuring Act's definition of transition costs. Transition
costs for which the Company will seek recovery include professional fees,
financing costs, consents relating to the transfer of assets, management
information system changes including billing system changes and public and
customer education and communications. These costs will be amortized over the
recovery period to match related revenues. The Company intends to vigorously
pursue remedies available to it should the PRC disallow recovery of reasonable
transition costs. Costs not recoverable will be expensed when incurred unless
these costs are otherwise permitted to be capitalized under current and future
accounting rules. Depending on the amount of non-recoverable transition costs,
if any, the resulting charge to earnings may have a material effect on the
future financial results and position of the Company.
Nuclear Regulatory Commission Prefunding
Pursuant to NRC rules on financial assurance requirements for the
decommissioning of nuclear power plants, the Company has a program for funding
its share of decommissioning costs for PVNGS through a sinking fund mechanism.
The NRC rules on financial assurance became effective on November 23, 1998. The
amended rules provide that a licensee may use an external sinking fund as the
exclusive financial assurance mechanism if the licensee recovers estimated
decommissioning costs through cost of service rates or a "non-bypassable
charge". Other mechanisms are prescribed, such as prepayment, surety methods,
insurance and other guarantees, to the extent that the requirements for
exclusive reliance on the fund mechanism are not met.
The Restructuring Act, as amended, allows for the recoverability of 50%
up to 100% of stranded costs including nuclear decommissioning costs. The
results of the 1998 triannual decommissioning cost study indicated that PNM's
share of the PVNGS decommissioning costs excluding spent fuel disposal would be
approximately $201 million. The Restructuring Act, as amended, specifically
identifies nuclear decommissioning costs as eligible for separate recovery over
a longer period of time than other stranded costs if the PRC determines a
separate recovery mechanism to be in the public interest. In addition, the
Restructuring Act, as amended, states that it does not require the PRC to issue
any order which would result in loss of eligibility to exclusively use external
sinking fund methods for decommissioning obligations pursuant to federal
regulations. When final determination of stranded cost recovery is made and if
the Company is unable to meet the requirements of the NRC rules permitting the
use of an external sinking fund because it is unable to recover all of its
estimated decommissioning costs through a non-bypassable charge, the Company may
have to pre-fund or find a similarly capital intensive means to meet the NRC
rules. There can be no assurance that such an event will not negatively affect
the funding of the Company's growth plans.
59
MERCHANT PLANT FILING
Senate Bill ("SB") 266, enacted by the 2001 session of the New Mexico
legislature, allowed public utilities to "invest in, construct, acquire or
operate" a generating plant not intended to provide retail electric service,
free of certain otherwise applicable regulatory requirements contained in the
Public Utility Act. By order entered on March 27, 2001, the PRC found that these
provisions of SB 266 raised issues such as cost allocations for ratemaking,
revenue allocations for off-system sales, how the Commission can ensure the
utility will meet its duty to provide service when the utility invests in such
generating plant, how that plant will be financed and how transactions between
regulated services and merchant plants will be conducted. The Company has filed
a pleading addressing these issues and testimony in response to interested
parties' requests. A hearing initially scheduled for June 2002, was vacated and
no new procedural schedule has yet been established.
In November 2001, the Company began settlement negotiations with the
PRC's utility staff and intervenors related to these PRC proceedings in order to
resolve a number of matters. In addition to the issues being examined in the
Company's merchant plant filing, discussions have included the future framework
for restructuring the electric industry in New Mexico under the Restructuring
Act, and a future retail electric rate path. The negotiations include the
potential implementation and effective date of rates that would replace those
approved under the rate freeze stipulation that remains in effect until January
1, 2003.
The Company is currently unable to predict the impact these proceedings
may have on its plans to expand its generating capacity and other operations.
WESTERN UNITED STATES WHOLESALE POWER MARKET
A significant portion of the Company's earnings in 2001 was derived from
the Company's wholesale power trading operations, which benefited from strong
demand and high wholesale prices in the Western United States. These market
conditions were driven by a number of separate factors, including electric power
supply shortages in the Western United States during the first half of the year,
weather conditions, gas supply costs and transmission constraints. As a result
of these factors, the wholesale power market in the Western United States became
extremely volatile and, while providing many marketing opportunities, presented
and continues to present significant risk to companies selling power into this
marketplace.
These conditions resulted in the well-publicized "California energy
crisis" and in the bankruptcy filings of the California Power Exchange ("Cal
PX") and of Pacific Gas & Electric Company, although the turmoil in the western
markets was not limited to California. However, over the last twelve months,
conditions in the western wholesale power market have changed substantially, as
the result of certain regulatory actions (see below), moderate weather
conditions, conservation measures, the construction of additional generation and
a decline in natural gas prices, as well as the lingering slowdown in the
regional economy. These changes have placed and are expected to continue to
place downward pressure on wholesale electricity prices, with the result that
the Company expects its earnings from wholesale power trading operations to be
significantly lower in the future than the levels seen during the first half of
2001.
60
In response to the turmoil in the Western energy market, the FERC
initially imposed a "soft" price cap of $150 per MWh for sales to the Cal PX and
the California Independent System Operator ("Cal ISO") that required any
wholesale sales of electricity into these markets be capped at $150 per MWh
unless the seller could demonstrate that its costs exceeded the cap. This price
cap was modified by FERC orders that directed certain power suppliers to provide
refunds for overcharges calculated on the basis of a formula that sanctioned
wholesale prices considerably in excess of the $150 per MWh level. Shortly
thereafter, the FERC adopted an order establishing prospective mitigation and a
monitoring plan for the California wholesale markets and which established a
further investigation of public utility rates in wholesale Western energy
markets. This plan replaced the $150 per MWh soft cap previously established and
applied during periods of system emergency. Subsequently, the FERC issued still
another order that changed the previous orders and expanded the price mitigation
approach to the entire Western region.
In July 2002, the FERC issued further orders to address wholesale power
prices in the Western market. On July 11, the FERC established a price cap of
$91.87 per MWh for the period ending September 30, 2002. On July 17, the FERC
entered an order, which will take effect October 1, 2002, raising the price cap
to $250 per MWh. This price cap can be affected by other factors that could
cause the cap to be below $250 per MWh. According to the FERC, this price cap
will spur new investment in generation and will foster the eventual return of a
robust competitive marketplace. The July 17 order also established mechanisms to
prevent power suppliers from engaging in market manipulation activities.
As a result of the foregoing conditions in the Western market, the FERC
and other federal and state governmental authorities are conducting
investigations and other proceedings relevant to the Company and other sellers.
The more significant of these in relation to the Company are summarized below.
California and Pacific Northwest Refund Proceedings
By order dated June 19, 2001, the FERC directed one of its administrative
law judges to convene a settlement conference to address potential refunds owed
by sellers into the California market. The settlement conference, in which the
Company participated, was ultimately unsuccessful, but the administrative law
judge called in his recommendation to the FERC for an evidentiary hearing to
resolve the dispute, suggesting that refunds were due; however, the estimated
refunds were significantly lower than demanded by California, and in most
instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO.
California had demanded refunds of approximately $9 billion from power
suppliers. On July 25, 2001, acting on the recommendation of the administrative
law judge, the FERC ordered an expedited fact-finding hearing to evaluate
refunds for spot market transactions in California. The FERC also ordered a
preliminary hearing to determine whether refunds were due resulting from
wholesale sales into the Pacific Northwest. The Pacific Northwest matter was
heard by an administrative law judge whose recommended decision declined to
order refunds resulting from sales into the Pacific Northwest, but the FERC has
not yet acted on this recommended decision. The hearing on potential California
refund obligations has not yet been completed and a recommended decision is not
anticipated until the second half of 2002. The Company is unable to predict the
ultimate outcome of these FERC proceedings, or whether the Company will be
directed to make any refunds as the result of a FERC order.
61
FERC Investigation of "Enron-Like" Trading Practices
The FERC has also initiated a market manipulation investigation,
partially in response to the Enron bankruptcy filing and to allegations that
Enron may have engaged in manipulation of portions of the Western wholesale
power market. In connection with that investigation all FERC jurisdictional and
non-jurisdictional sellers into western electric and gas markets have been
required to submit data regarding short-term transactions in 2000-2001. The
Company made its data submission on April 2, 2002. Subsequently, in May 2002,
new Enron documents came to light that raised additional concerns about Enron's
trading practices. In light of these new revelations, the FERC issued additional
orders in the pending investigation requiring sellers to respond to detailed
questions by admitting or denying that they had engaged in trading practices
similar to those practiced by Enron and certain other sellers, including
so-called "wash" transactions. In its responses, the Company denied that it had
engaged in activities such as those identified in Enron's memos and also denied
engaging in "wash" transactions. Where appropriate, the Company's responses
addressed any arguable similarities between any of its trading activities and
those under investigation by the FERC. The Company cannot predict the outcome of
this investigation.
California Power Exchange Bankruptcy
In 2001, approximately $2 million in wholesale power sales by the Company
were made directly to the Cal PX, which was the main market for the purchase and
sale of electricity in the state in the beginning of 2001, or the Cal ISO, which
manages the state's electricity transmission network. In January and February
2001, SCE and PG&E, major purchasers of power from the Cal PX and ISO, defaulted
on payments due the Cal PX for power purchased from the Cal PX in 2000. These
defaults caused the Cal PX to seek bankruptcy protection. PG&E subsequently also
sought bankruptcy protection. The Company has filed its proofs of claims in the
Cal PX and PG&E bankruptcy proceedings. Total amounts due the Company from the
Cal PX or Cal ISO for power sold to them in 2000 and 2001 total approximately $7
million. The Company has provided allowances for the total amount due from the
Cal PX and Cal ISO.
Prior to its bankruptcy filing, the Cal PX undertook to charge back the
defaults of SCE and PG&E to other market participants, in proportion to their
participation in the markets. The Company was invoiced for $2.3 million as its
proportionate share under the Cal PX tariff. The Company, as well as a number of
power marketers and generators, filed complaints with the FERC to halt the Cal
PX's attempt to collect these payments under the charge-back mechanism, claiming
the mechanism was not intended for these purposes, and even if it was so
intended, such an application was unreasonable and destabilizing to the
California power market. The FERC issued a ruling on these complaints
eliminating the "charge-back" mechanism.
California Attorney General Complaint
In March 2002, the California Attorney General filed a complaint at the
FERC against numerous sellers regarding prices for sales into the Cal ISO and
Cal PX and to the California Department of Water Resources ("Cal DWR"). The
Company was among the sellers identified in this complaint and the Company filed
its answer and motion to intervene. In its answer, the Company defended its
pricing and challenged the theory of liability underlying the California
Attorney General's complaint. On May 31, 2002, the FERC entered an order denying
62
the rate relief requested in the complaint, but directing sellers, including the
Company, to comply with additional reporting requirements with regard to certain
wholesale power transactions. The Company has made required filings under the
May 31 order. The Attorney General has filed a request for rehearing that is
pending at the FERC. As addressed below, the California Attorney General has
also threatened litigation against the Company in state court in California
based on similar allegations.
California Attorney General Threatened Litigation
The California Attorney General has filed several lawsuits in California
state court against certain power marketers for alleged unfair trade practices
involving alleged overcharges for electricity. By letter dated April 9, 2002,
the California Attorney General notified the Company of his intent to file a
complaint in California state court against the Company concerning its alleged
failure to file rates for wholesale electricity sold in California and for
allegedly charging unjust and unreasonable rates in the California markets. For
each asserted violation, the letter indicates an intent to seek penalties of
$2,500. The letter invited the Company to contact the California Attorney
General's office before the complaint was filed, and the Company has met twice
with the California Attorney General's office. Further discussions are
contemplated. To date, suit has not been filed by the Attorney General and the
Company cannot predict the outcome of this matter.
California Antitrust Litigation
Several class action lawsuits have been filed in California state courts
against electric generators and marketers, alleging that the defendants violated
the law by manipulating the market to grossly inflate electricity prices. Named
defendants in these lawsuits include Duke Energy ("Duke") and related entities
along with other named sellers into the California market and numerous other
"unidentified defendants." These lawsuits were consolidated for hearing in state
court in San Diego. On May 3, 2002, the Duke defendants in the foregoing state
court litigation served a cross-claim on the Company. Duke also cross-claimed
against many of the other sellers into California. Duke asked for declaratory
relief and for indemnification for any damages that might ultimately be imposed
on Duke. Several defendants have removed the case to federal court and a motion
is pending to remand the case to state court. The Company has joined with other
cross-defendants in motions to dismiss the cross-claim. The Company cannot
predict the outcome of this matter.
Credit Issues
As a result of the slowdown in the wholesale electric market and the
bankruptcy of a major trader in 2001, a significant number of companies that
trade in electricity have experienced liquidity problems, resulting in a
downgrade in their credit ratings. This has had the effect of reducing the
number of credit worthy companies in the market. Some companies have curtailed
their activity or exited the business altogether. The Company's credit risk is
monitored by its Risk Management Committee ("RMC"), which is comprised of senior
finance and operations managers. The Company seeks to minimize its exposure
through established credit limits, a diversified customer base and the
structuring of transactions to take advantage of offsetting positions with its
63
customers. The Company trades with companies of various credit quality. For
those companies who are not investment grade, the Company provides a minimal
amount of credit. For companies that are designated as key strategic business
partners by the RMC but are not investment grade, the Company attempts to obtain
a parental guarantee (if investment grade) or other acceptable collateral.
Currently, 71% of trading partners who are not investment grade have such credit
enhancements in place. In the current downturn, the Company may be exposed to
credit risk if any of its customers experience liquidity problems.
With the demise of the Cal PX in February 2001, the Cal DWR commenced a
program of purchasing electric power needed to supply California utility
customers serviced by PG&E and SCE as these utilities lacked the liquidity to
purchase supplies. The purchases were financed by legislative appropriation,
with the expectation that this funding would be replaced with the issuance of
revenue bonds by the state. In the first quarter of 2001, the Company began to
sell power to the Cal DWR. The Company has regularly monitored its credit risk
with regard to the Cal DWR sales and believes its exposure is prudent.
In addition to sales directly to California, the Company sells power to
customers in other jurisdictions who sell to California and whose ability to pay
the Company may be dependent on payment from California. The Company is unable
to determine whether non-California power sales ultimately are resold in the
California market. To the extent these customers who sell power into California
are dependent on payment from California to make their payments to the Company,
the Company may be exposed to credit risk, which did not exist prior to the
California situation.
In 2001, in response to the increased credit risk and market price
volatility described above, the Company provided an additional allowance against
revenue of $3.8 million for anticipated losses to reflect management's estimate
of the increased market and credit risk in the wholesale power market and its
impact on 2001 revenues. The Company recorded additional reserves of $780,000 in
the second quarter of 2002 as a result of the continuing credit degradation of
many of its counterparties. Based on information available at June 30, 2002, the
Company believes the total allowance for anticipated losses, currently
established at $12.8 million, is adequate for management's estimate of potential
uncollectible accounts. The Company will continue to monitor the wholesale power
marketplace and adjust its estimates accordingly.
TERMINATION OF WESTERN RESOURCES TRANSACTION
On November 9, 2000, PNM and Western Resources announced that both
companies' Boards of Directors approved an agreement under which PNM would
acquire the Western Resources electric utility operations in a tax-free,
stock-for-stock transaction. The agreement required that Western Resources
split-off its non-utility businesses to its shareholders prior to closing.
In July 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for a $151 million increase. After rehearing the KCC established the
rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
64
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state
court. On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect. However, the Company
subsequently received a letter dated May 28, 2002, from counsel for Western
Resources purporting to terminate the agreement and demanding payment of a $25
million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the
Company in New York state court alleging breach of contract and fraud. Western
Resources alleged that the Company's January 7 letter constituted a withdrawal
or adverse modification of the Company's adoption of the agreement or
recommendation that its shareholders approve the agreement. As a result, Western
Resources claims that the Company is liable for a $25 million termination fee
plus costs and expenses (including attorneys fees) incurred in connection with
the litigation. Western Resources also claims that the Company committed fraud
by not timely disclosing to Western Resources its intentions not to proceed with
the transaction and is seeking additional unspecified damages. The Company
believes that the counterclaims filed by Western Resources are without merit and
intends to vigorously defend itself against them. The Company also intends to
vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment
and for Dismissal of Counterclaims and Defenses.
The Company is currently unable to predict the outcome of its litigation
with Western Resources.
Effects of Certain Events on Future Revenues
On October 1, 1999, Western Area Power Administration ("WAPA") filed a
petition at the FERC requesting the FERC, on an expedited basis, to order the
Company to provide network transmission service to WAPA under the Company's Open
Access Transmission Tariff on behalf of the United States Department of Energy
("DOE") as contracting agent for Kirtland Air Force Base ("KAFB").
65
In 2001, FERC issued a "proposed" order directing the Company to provide
transmission service, but left the terms of service to be negotiated by the
parties and subject to final FERC review and determination. In January 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The settlement agreement reserves
the Company's rights to seek rehearing and judicial review of any final order
and to present other legal claims. On April 12, 2002, the FERC approved the
settlement, and on April 29, 2002, the FERC issued its Final Order directing the
Company to provide the service. WAPA requested rehearing of the April 12 order
approving the settlement, and FERC has issued an order granting rehearing of the
April 12 order for the purpose of further consideration. The Company requested
rehearing of the April 29 final order. Thirty days passed without FERC action on
the Company's request for rehearing, and the Company filed a petition for review
in the United States Court of Appeals for the Tenth Circuit on July 19, 2002. A
related PRC proceeding has been stayed, pending the outcome of the FERC case.
Should DOE on behalf of KAFB choose to use WAPA for purchase and
transmission services instead of the current retail sale that the Company makes
to DOE, the effect of the FERC's proposed order to provide transmission service,
depends upon the Company's ability to sell the power to a different customer and
the price that the Company would obtain if it makes such a sale. Depending on
market conditions, the Company estimates that the impact of the order will be a
loss of revenues of approximately $3 to $6 million.
NEW SOURCE REVIEW RULES
In November 1999, the Department of Justice at the request of the EPA
filed complaints against seven companies alleging the companies over the past 25
years had made modifications to their plants in violation of the New Source
Review ("NSR") requirements and in some cases the New Source Performance
Standards ("NSPS") regulations, which could result in the requirement to make
costly environmental additions to older power plants. Whether or not the EPA
will prevail is unclear at this time. The EPA has reached a settlement with one
of the companies sued by the Justice Department. Discovery continues in the
pending litigation. No complaint has been filed against the Company by the EPA,
and the Company believes that all of the routine maintenance, repair, and
replacement work undertaken at its power plants was and continues to be in
accordance with the requirements of NSR and NSPS. However, by letter dated
October 23, 2000, the New Mexico Environment Department ("NMED") made an
information request of the Company, advising the Company that the NMED was in
the process of assisting the EPA in the EPA's nationwide effort "of verifying
that changes made at the country's utilities have not inadvertently triggered a
modification under the Clean Air Act's Prevention of Significant Determination
("PSD") policies." The Company has responded to the NMED information request. In
late June 2002, the Company received another information request from the NMED
for a list of capital budget item projects budgeted or completed in 2001 or
2002. The Company has responded to this NMED information request.
The National Energy Policy released in May 2001 by the National Energy
Policy Development Group called for a review of the pending EPA enforcement
actions. As a result of that review, on June 14, 2002 the EPA announced its
intention to pursue steps to increase energy efficiency, encourage emissions
reductions and make improvements and reforms to the NSR program. The EPA
announced that, among other things, the NSR program had impeded or resulted in
66
the cancellation of projects that would maintain or improve reliability,
efficiency and safety of existing power plants. However, the EPA's June 2002
announcement contemplates further rulemakings on NSR-related issues and
expressly cautions that the announcement is not intended to affect pending NSR
enforcement actions. Therefore, the ultimate resolution of NSR-related issues
raised by the enforcement actions remains unclear and if the EPA were to prevail
in the position advanced in the pending litigation, the Company may be required
to make significant capital expenditures, which could have a material adverse
effect on the Company's financial position and results of operations.
Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the Grand Canyon Trust and
Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that the Company and
co-owners of the SJGS violated the Clean Air Act, and the implementing federal
and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002,
the GCT filed suit in federal district court in New Mexico against the Company
(but not against the other SJGS co-owners). The suit alleges two violations of
the Clean Air Act and related regulations and permits. First GCT argues that the
plant has violated, and is currently in violation of, the federal Prevention of
Significant Deterioration ("PSD") rules, as well as the corresponding provisions
of the New Mexico Administrative Code, at all four units. Second, GCT alleges
that the plant has "regularly violated" the 20% opacity limit contained in
SJGS's operating permit and set forth in federal and state regulations at Units
1, 3 and 4. The lawsuit seeks penalties as well as injunctive and declaratory
relief. The Company filed its answer in federal court on June 6, 2002, denying
the material allegations in the complaint. The parties are presently addressing
with the federal magistrate a discovery schedule. Based on its investigation to
date, the Company firmly believes that the allegations are without merit and
vigorously disputes the allegations. The Company has always and continues to
adhere to high environmental standards as evidenced by its ISO 14000
certification. The Company is, however, unable to predict the ultimate outcome
of the matter.
NATURAL GAS EXPLOSION
On April 25, 2001, a natural gas explosion occurred in Santa Fe, New
Mexico. The apparent cause of the explosion was a leak from a Company line near
the location. The explosion destroyed a small building and injured two persons
who were working in the building. The Company's investigation indicates that the
leak was an isolated incident likely caused by a combination of corrosion and
increased pressure. The Company also is cooperating with an investigation of the
incident by the PRC's Pipeline Safety Bureau, which issued its report on March
18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the
New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the
Company by the injured persons along with several claims for property and
business interruption damages have been resolved. There can be no assurance that
the outcome of this matter will not have a material impact on the results of
operations and financial position of the Company.
NAVAJO NATION TAX ISSUES
Arizona Public Service Company ("APS"), the operating agent for Four
Corners, has informed the Company that in March 1999, APS initiated discussions
with the Navajo Nation regarding various tax issues in conjunction with the
expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation
in 1985. The tax waiver pertains to the possessory interest tax and the business
67
activity tax associated with the Four Corners operations on the reservation. The
Company believes that the resolution of these tax issues will require an
extended process and could potentially affect the cost of conducting business
activities on the reservation. The Company is unable to predict the ultimate
outcome of discussions with the Navajo Nation regarding these tax issues and
cannot estimate with any certainty the potential impact on the Company's
operations.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed, by a landowner owning property in the
vicinity of SJGS, against the Company and the owner of the coal mine that
supplies coal to the plant. The lawsuit was served on the defendants on June 11,
2002. The complaint seeks $20 million in damages, plus pre-judgment interest and
punitive damages, based on allegations related to the alleged discharge of
pollutants into an arroyo near the plant, including damage to the plaintiff's
livestock. A jury trial has been demanded. The Company is vigorously defending
this matter, but is unable to predict the outcome of this matter.
ARCHEOLOGICAL SITE DISTURBANCE
The Company hired a contractor, Great Southwestern Construction, Inc.
("Great Southwestern"), to conduct certain "climb and tighten" activities on a
number of electric transmission lines in New Mexico between July 2001 and
December 2001. Those lines traverse a mix of federal, state, tribal and private
properties in New Mexico. In late May 2002, the U.S Forest Service ("USFS")
notified the Company that apparent disturbances to archeological sites had been
discovered in and around the rights-of-way for the Company's transmission lines
in the Carson National Forest in New Mexico. Great Southwestern performed "climb
and tighten" activities on those transmission lines. The Company has confirmed
the existence of the disturbances, as well as disturbances associated with
certain arroyos that may raise issues under section 404 of the Clean Water Act.
The Company has given the Corps of Engineers notice concerning the disturbances
in arroyos. The Corps of Engineers has acknowledged the Company's notice and
asked the Company to cooperate in addressing these disturbances. No formal or
written demand by the USFS has been made on the Company with respect to this
matter, but the USFS has verbally instructed the Company to undertake an
assessment and possible related mitigation measures with respect to the
archeological sites in question. The Company has contracted for an archeological
assessment and a proposed remediation plan with respect to the disturbances. The
Company has provided Great Southwestern with notice and a demand for indemnity.
The Company is unable to predict the outcome of this matter and cannot estimate
with any certainty the potential impact on the Company's operations.
NEW AND PROPOSED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" ("SFAS 143"). In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the
recognition of a liability for legal obligations associated with the retirement
of a tangible long-lived asset that result from the acquisition, construction or
development or the normal operation of a long-lived asset. The asset retirement
68
obligation is required to be recognized at its fair value when incurred. The
cost of the asset retirement obligation is required to be capitalized by
increasing the carrying amount of the related long-lived asset by the same
amount as the liability. This cost must be expensed using a systematic and
rational method over the related asset's useful life. SFAS 143 is effective for
the Company beginning January 1, 2003. The Company is currently assessing the
impact of SFAS 143 and is unable to predict its impact on the Company's
operating results and financial position at this time.
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the
FASB issued SFAS 144. The statement retains the requirements of the previously
issued pronouncement on asset impairment, Statement of Financial Accounting
Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the
scope of SFAS 121, provides for a probability-weighted cash flow estimation
approach for estimating possible future cash flows, and establishes a "primary
asset" approach for a group of assets and liabilities that represents the unit
of accounting to be evaluated for impairment. In addition, SFAS 144 changes the
measurement of long-lived assets to be disposed of by sale, as accounted for by
Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued
operations are no longer measured on a net realizable value basis, and their
future operating losses are no longer recognized before they occur. The Company
does not believe SFAS 144 will have a material effect on its future operating
results or financial position.
Statement of Financial Accounting Standards No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This
statement updates and clarifies existing accounting pronouncements for treatment
of gains and losses from extinguishment of debt and eliminates an inconsistency
between required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have similar economic effects as
sale-leaseback transactions. According to the old policy, gains and losses from
extinguishment of debt were classified as extraordinary gains and losses. The
current statement permits gains and losses from extinguishment of debt to be
classified as ordinary and included in income from operations, unless they are
unusual in nature or occur infrequently and therefore included as an
extraordinary item.
Emerging Issues Task Force ("EITF") Issue 02-03 "Recognition and
Reporting of Gains and Losses" on Energy Trading Contracts under EITF Issues No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts
in Applying Issue No. 98-10." This EITF issue addresses various aspects of the
accounting for contracts involved in energy trading and risk management
activities. The EITF concluded that all mark-to-market gains and losses on
energy trading contracts should be shown net in the income statement whether or
not settled physically. The EITF did not reach a consensus and continues to
debate whether the recognition of unrealized gains and losses at inception of an
energy trading contract is appropriate in the absence of quoted market prices or
current market transactions for contracts with similar terms. The EITF also
expanded the disclosure requirements for energy trading activities.
Implementation of the consensus for recording energy trading activities net is
effective for the Company beginning with its 2002 third quarter financial
statements. Comparative financial statements for prior periods are required to
be reclassified to conform to the EITF's consensus. The Company is currently
assessing the impact of implementing EITF Issue No. 02-03 and is unable to
predict its effect on the Company's presentation of operating results. The SEC
69
has indicated that financial statement reclassifications related to periods
previously audited by Arthur Andersen, LLP ("Arthur Andersen") may require the
successor auditor to audit the prior periods and issue a new audit report.
Arthur Andersen audited the Company's financial statements for the fiscal years
2001 and 2000.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events are made
pursuant to the Private Securities Litigation Reform Act of 1995. Readers are
cautioned that all forward-looking statements are based upon current
expectations and are subject to risk and uncertainties. The Company assumes no
obligation to update this information.
Because actual results may differ materially from expectations, the
Company cautions readers not to place undue reliance on these statements. A
number of factors, including weather, fuel costs, changes in the local and
national economy, changes in supply and demand in the market for electric power,
the outcome of litigation relating to the Company's terminated transaction with
Western Resources, the performance of generating units and transmission system,
the transition to the underground mine for the supply of coal to SJGS, the
creditworthiness of the Company's marketing and trading counterparties, the
success of the Company's planned generation expansion and state and federal
regulatory and legislative decisions and actions, including the wholesale
electric power pricing mitigation plan ordered by FERC, rulings issued by the
PRC pursuant to the Electric Utility Industry Restructuring Act of 1999, as
amended, and in other cases now pending or which may be brought before the FERC
and the PRC and any action by the New Mexico Legislature to further amend or
repeal that Act, or other actions relating to restructuring or stranded cost
recovery, or federal or state regulatory, legislative or legal action connected
with the California wholesale power market and wholesale power markets in the
West, could cause the Company's results or outcomes to differ materially from
those indicated by such forward-looking statements in this filing.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company uses derivative financial instruments to manage risk as it
relates to changes in natural gas and electric prices, changes in interest rates
and, historically, adverse market changes for investments held by the Company's
various trusts. The Company also uses certain derivative instruments for bulk
power electricity trading purposes in order to take advantage of favorable price
movements and market timing activities in the wholesale power markets.
Information about the Company's financial instruments is set forth in the
Financial Instruments note in the Notes to Consolidated Financial Statements and
incorporated by reference. The following additional information is provided.
Risk Management
The Company controls the scope of its various forms of risk through a
comprehensive set of policies and procedures and oversight by senior level
management and the Board of Directors. The Board's Finance Committee sets the
risk limit parameters. An internal risk management committee ("RMC"), comprised
of corporate and business segment officers, oversees all of the activities,
which include commodity price, credit, equity, interest rate and business risks.
70
The RMC has oversight for the ongoing evaluation of the adequacy of the risk
control organization and policies. The Company has a risk control organization,
headed by the Director of Financial Risk Management ("Risk Manager"), which is
assigned responsibility for establishing and enforcing the policies, procedures
and limits and evaluating the risks inherent in proposed transactions, on an
enterprise-wide basis.
The RMC's responsibilities specifically include: establishment of a
general policy regarding risk exposure levels and activities in each of the
business units; recommendation of the types of instruments permitted for
trading; authority to establish a general policy regarding counterparty exposure
and limits; authorization and delegation of trading transaction limits for
trading activities; review and approval of controls and procedures for the
trading activities; review and approval of models and assumptions used to
calculate mark-to-market and risk exposure; authority to approve and open
brokerage and counterparty accounts for derivative trading; review for trading
and risk activities; and quarterly reporting to the Finance Committee and the
Board of Directors on these activities.
The RMC also proposes Value at Risk ("VAR") limits to the Finance
Committee. The Finance Committee ultimately sets the aggregate VAR limit.
It is the responsibility of each business unit to create its own control
and procedures policy for trading within the parameters established by the
Finance Committee. The RMC reviews and approves these policies, which are
created with the assistance of the Chief Accounting Officer, Director of
Internal Audit and the Risk Manager. Each business unit's policies address the
following controls: authorized risk exposure limits; authorized trading
instruments and markets; authorized traders; policies on segregation of duties;
policies on marking to market; responsibilities for trade capture; confirmation
procedures; responsibilities for reporting results; statement on the role of
derivatives trading; and limits on individual transaction size (nominal value)
for traders.
To the extent an open position exists, fluctuating commodity prices can
impact financial results and financial position, either favorably or
unfavorably. As a result, the Company cannot predict with precision the impact
that its risk management decisions may have on its businesses, operating results
or financial position.
Commodity Risk
Trading and marketing operations often involve market risks associated
with managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. The Company routinely
enters into forward contracts and options to hedge purchase and sale
commitments, fuel requirements and to minimize the risk of market fluctuations
on the Generation and Trading Operations.
The Company's wholesale power marketing operations, including both firm
commitments and trading activities, are managed through an asset backed
strategy, whereby the Company's aggregate net open position is covered by its
own excess generation capabilities. The Company is exposed to market risk if its
generation capabilities were disrupted or if its retail load requirements were
greater than anticipated. If the Company were required to cover all or a portion
of its net open contract position, it would have to meet its commitments through
market purchases.
71
The Company assesses the risk of these derivatives using the VAR method,
in order to maintain the Company's total exposure within management-prescribed
limits. The Company utilizes the variance/covariance model of VAR, which is a
probabilistic model that measures the risk of loss to earnings in market
sensitive instruments. The variance/covariance model relies on statistical
relationships to analyze how changes in different markets can affect a portfolio
of instruments with different characteristics and market exposure. VAR models
are relatively sophisticated; however, the quantitative risk information is
limited by the parameters established in creating the model. The instruments
being evaluated may trigger a potential loss in excess of calculated amounts if
changes in commodity prices exceed the confidence level of the model used. The
VAR methodology employs the following critical parameters: volatility estimates,
market values of open positions, appropriate market-oriented holding periods and
seasonally adjusted correlation estimates. The Company uses a holding period of
three days as the estimate of the length of time that will be needed to
liquidate the positions. The volatility and the correlation estimates measure
the impact of adverse price movements both at an individual position level as
well as at the total portfolio level. The confidence level established is 99%.
For example, if VAR is calculated at $10 million, it is estimated at a 99%
confidence level that if prices move against the Company's positions, the
Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10
million in the three days that it would take to liquidate the portfolio.
The Company accounts for the sale of electric generation in excess of its
retail needs or the purchase of power for retail needs as non-trading. Purchases
for resale and subsequent resales are accounted for as energy trading contracts.
With respect to the Company's trading portfolio, the VAR was $0.8 million at
June 30, 2002. The Company calculates a portfolio VAR, which in addition to its
trading portfolio includes all non-trading designated contracts, its generation
assets excluded from retail rates and any capacity in excess of retail needs.
This excess is determined using average peak forecasts for the respective block
of power in the forward market. The Company's portfolio VAR was $5.0 million at
June 30, 2002.
The Company's VAR is regularly monitored by the Company's RMC. The RMC
has put in place procedures to ensure that increases in VAR are reviewed and, if
deemed necessary, acted upon to reduce exposures. The VAR represents an estimate
of the potential gains or losses that could be recognized on the Company's
wholesale power marketing portfolio given current volatility in the market, and
is not necessarily indicative of actual results that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ due to actual fluctuations in market rates, operating
exposures, and the timing thereof, as well as changes to the Company's wholesale
power marketing portfolio during the year.
In addition, the Company is exposed to credit losses in the event of
non-performance or non-payment by counterparties. The Company uses a credit
management process to assess and monitor the financial conditions of
counterparties. Credit exposure is also regularly monitored by the RMC. The
Company provides for losses due to market and credit risk. The Company's credit
risk with its largest counterparty as of June 30, 2002 was $4.5 million.
The Company hedges certain portions of natural gas supply contracts in
order to protect its retail customers from adverse price fluctuations in the
natural gas market. The financial impact of all hedge gains and losses,
including the related costs of the program, is recoverable through the Company's
purchased gas adjustment clause as deemed prudently incurred by the PRC. As a
result, earnings are not affected by gains and losses generated by these
instruments.
72
Interest Rate Risk
As of June 30, 2002, the Company has an investment portfolio of
fixed-rate government obligations and corporate securities, which were subject
to the risk of loss, associated with movements in market interest rates. For
accounting purposes, the portfolio is classified as available-for-sale and is
marked-to-market. As a result, unrealized losses resulting from interest rate
increases are recorded as a component of comprehensive income. If interest rates
were to rise 50 basis points from their levels at June 30, 2002, the fair value
of these instruments would decline by 69.5% or $0.7 million. In addition,
because of this interest rate sensitivity, early or unplanned redemption of
these investments in a period of increasing interest rates would subject the
Company to risk of a realized loss of principal as the fair market value of
these investments would be less than their carrying value. The Company employs
investment managers to mitigate this risk. As part of its investing strategies,
the Company has diversified its portfolio with investments of varying maturity
and obligors and limits credit exposure to high investment grade quality
investments.
The Company has long-term debt which subjects it to the risk of loss
associated with movements in market interest rates. All of the Company's
long-term debt is fixed-rate debt, and therefore, does not expose the Company's
earnings to a risk of loss due to adverse changes in market interest rates.
However, the fair value of these debts instruments would increase by
approximately 4.2% or $40.4 million if interest rates were to decline by 50
basis points from their levels at June 30, 2002. As of June 30, 2002, the fair
value of the Company's long-term debt was $962 million as compared to a
book-value of $954 million. In general, an increase in fair value would impact
earnings and cash flows if the Company were to re-acquire all or a portion of
its debt instruments in the open market prior to their maturity. Certain
issuances of the Company's debt have call dates in December 2002 and August
2003. To hedge against the risk of rising interest rates and their impact on the
economies of calling the debt, the Company has entered into two forward starting
swaps in 2001 and three additional contracts in 2002. These forward interest
rate swaps effectively lock-in interest rates for the notional amount of the
debt that is callable at a rate of approximately 4.9% plus an adjustment for the
Company's and industry's credit rating. At June 30, 2002, the fair market value
of these derivative financial instruments was approximately $3.0 million in the
Company's favor.
The Company contributed $6.1 million in 2001 to a trust established to
fund decommissioning costs for PVNGS. In January 2002, the Company contributed
$23.5 million for plan year 2001 to the trust for the Company's pension plan,
and other post retirement benefits. The securities held by the trusts had an
estimated fair value of $473.7 million as of June 30, 2002, of which
approximately 29% were fixed-rate debt securities that subject the Company to
risk of loss of fair value with movements in market interest rates. If rates
were to increase by 50 basis points from their levels at June 30, 2002, the
decrease in the fair value of the securities would be 3.1% or $4.3 million. The
Company does not currently recover or return in jurisdictional rates losses or
gains on these securities; therefore, the Company is at risk for shortfalls in
its funding of its obligations due to investment losses. However, the Company
does not believe that long-term market returns over the period of funding will
be less than required for the Company to meet its obligations.
73
Equity Market Risk
As discussed above under Interest Rate Risk, the Company contributes to
trusts established to fund its share of the decommissioning costs of PVNGS and
other post retirement benefits. The trust holds certain equity securities as of
June 30, 2002. These equity securities also expose the Company to losses in fair
value. Approximately 54% of the securities held by the various trusts were
equity securities as of June 30, 2002. Similar to the debt securities held for
funding decommissioning and certain pension and other postretirement costs, the
Company does not recover or return in jurisdictional rates losses or gains on
these equity securities.
In 2001, the Company implemented an enhanced cash management strategy
using derivative instruments based on the Standard & Poors 100 and 500 indices.
The strategy is designed to capitalize on high market volatility or benefit from
market direction. An investment manager is utilized to execute the program. The
program is carefully managed by the RMC and limited to a one-day VAR of $5
million and a loss limit of $7.5 million. Trades are closed-out before the end
of a reporting period and typically within the same day of execution. Recently,
the RMC recommended and the Finance Committee approved the use of derivatives
based on the Nasdaq composite index.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The following represents a discussion of legal proceedings that first
became a reportable event in the current year or material developments for those
legal proceedings previously reported in the Company's 2001 Annual Report on
Form 10-K ("Form 10-K"). This discussion should be read in conjunction with Item
3. - Legal Proceedings in the Company's Form 10-K.
NAVAJO NATION ENVIRONMENTAL ISSUES
Four Corners is located on the Navajo Reservation and is held under an
easement granted by the federal government as well as a lease from the Navajo
Nation. APS is the Four Corners operating agent and the Company owns a 13%
ownership interest in Units 4 and 5 of Four Corners.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the
Navajo Nation Pesticide Act (collectively, the "Navajo Acts"). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water, and pesticide
activities, including those that occur at Four Corners. The Four Corners
participants dispute that purported authority, and by letter dated October 12,
1995, the Four Corners participants requested the United States Secretary of the
Interior to resolve their dispute with the Navajo Nation regarding whether or
not the Navajo Acts apply to operations of Four Corners. On October 17, 1995,
the Four Corners participants filed a lawsuit in the District Court of the
Navajo Nation, Window Rock District, seeking, among other things, a declaratory
judgment that:
74
o the lease and federal easement preclude the application of the Navajo Acts
to the operations of Four Corners; and
o the Navajo Nation and its agencies and courts lack adjudicatory
jurisdiction to determine the enforceability of the Navajo Acts as applied
to Four Corners.
On October 18, 1995, the Navajo Nation and the Four Corners participants
agreed to indefinitely stay these proceedings so that the parties may attempt to
resolve the dispute without litigation. The Secretary and the Court have stayed
these proceedings pursuant to a request by the parties. The Company cannot
currently predict the outcome of this matter.
In February 1998, the EPA issued regulations identifying those Clean Air
Act provisions for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA has announced that it has not yet determined whether
the Clean Air Act would supersede pre-existing binding agreements between the
Navajo Nation and the Four Corners participants that could limit the Navajo
Nation's environmental regulatory authority over Four Corners. The Company
believes that the Clean Air Act does not supersede these pre-existing
agreements. The Company cannot currently predict the outcome of this matter.
On August 8, 2000, the EPA signed an Eligibility Determination for the
Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA
determined that the Navajo Nation was eligible to receive grants under the Clean
Air Act. On September 8, 2001, after learning of the eligibility determination,
APS, as Four Corners operating agent, filed a Petition for Review of the EPA's
decision in the United States Court of Appeals for the Ninth Circuit in order to
ensure that the EPA's August 2000 determination not be construed to constitute a
determination of the Navajo Nation's authority to regulate Four Corners. APS,
the EPA and other parties have requested that the Court stay any further
briefing while they negotiate a settlement.
In April 2000, the Navajo Tribal Council approved operating permit
regulations under the Navajo Nation Air Pollution Prevention and Control Act.
The Four Corners participants believe that the regulations fail to recognize
that the Navajo Nation did not intend to assert jurisdiction over Four Corners.
On July 12, 2000, the Four Corners participants each filed a petition with the
Navajo Supreme Court for review of the operating permit regulations. The Company
cannot currently predict the outcome of this matter.
KAFB CONTRACT
In 1999, the Company was informed that the DOE had entered into an agency
agreement with WAPA on behalf of KAFB, one of the Company's largest retail
electric customers, by which WAPA would competitively procure power for KAFB.
The proposed wholesale power procurement was to begin at the expiration of
KAFB's power service contract with the Company in December 1999. On May 4, 1999,
the Company received a request for network transmission service from WAPA
pursuant to Section 211 of the Federal Power Act to facilitate the delivery of
wholesale power to KAFB over the Company's transmission system. The Company
denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB
is and will continue to be a retail customer until the date that KAFB can elect
customer choice service under the provisions of the Restructuring Act of 1999.
The Company also cited several provisions of federal law that prohibit the
provision of such service to WAPA. On October 1, 1999, WAPA filed a petition
requesting the FERC, on an expedited basis, to order the Company to provide
network transmission service to WAPA on behalf of DOE and several other entities
75
located on KAFB under the Company's Open Access Transmission Tariff. The
petition claimed KAFB is a wholesale customer of the Company, not a retail
customer. By order entered on April 13, 2001 the FERC denied the WAPA
transmission application. The FERC order determined, among other things, that
WAPA had failed to demonstrate that its sales to DOE are sales for resale and
also that WAPA failed to qualify for certain claimed exemptions under the
Federal Power Act that would have entitled it to provide expanded service to
DOE. WAPA requested rehearing of FERC's April 13, 2001 order.
In a proposed order issued on June 13, 2001, FERC granted WAPA's request
for rehearing. FERC determined that WAPA qualified for an exemption to the
prohibition against an order requiring service to retail customers and that FERC
therefore could require the Company to provide the requested service. FERC
directed the Company and WAPA to engage in negotiations concerning rates, terms
and conditions of service, including compensation. On January 18, 2002, the
parties submitted a settlement agreement resolving most of the issues relating
to the rates, terms and conditions of service. The partial settlement reserved
one issue for FERC decision or further proceedings. The reserved issue relates
to whether WAPA is entitled to a credit against payments for transmission
service for certain facilities located near KAFB. The settlement agreement filed
at FERC reserves the Company's rights to seek rehearing and judicial review of
any final order and to present other legal claims. On April 12, 2002, the FERC
approved the settlement. On April 29, 2002, the FERC issued its final order
directing the Company to provide service. WAPA requested rehearing of the April
12 order approving the settlement, and FERC issued an order granting rehearing
for further consideration. The Company requested rehearing of the April 29 final
order directing the Company to provide service. Thirty days passed without FERC
action on the Company's request for rehearing and it is deemed denied. The
Company filed a petition for review of the final order and the denial of its
request for rehearing in the United States Court of Appeals for the Tenth
Circuit on July 19, 2002.
In a separate but related proceeding, the Company and the United States
Executive Agencies on behalf of KAFB are involved in a PRC case regarding a
dispute over the specific Company tariff language under which the Company
provides retail service to KAFB. The Company agreed to continue to provide
service to KAFB after expiration of the contract and KAFB continues to purchase
retail service pending resolution of all relevant issues. The PRC case has been
held in abeyance, pending the outcome of the FERC proceeding.
AVISTAR SEVERANCE
When the Company sold its water utility assets to the City of Santa Fe
("City") in 1995, the parties also entered into a Maintenance and Operations
Agreement ("Agreement"), agreeing that the City would offer employment to the
water utility employees when the Agreement expired. The Agreement was assigned
to Avistar, Inc., and it expired in July 2001. The City assumed all maintenance
and operations, and offered employment to the employees.
Because the employees would continue performing the same jobs at the same
location(s), the Company had previously excluded the non-union employees from
eligibility for severance benefits under the Company's non-union severance
plans. Similarly, the IBEW Local 611 had been on notice that the Company had
negotiated for the continued employment of the IBEW-represented employees,
making them ineligible for severance benefits under Article 24 of the Collective
Bargaining Agreement ("CBA") between the Company and the IBEW.
76
In July 2001, the Agreement ended, and most of the water operations
employees accepted employment with the City. However, on March 27, 2001, the
IBEW filed a grievance claiming that about twenty-eight represented employees
now employed by the City are nonetheless eligible for severance benefits under
Article 24 of the CBA. The Company has denied their eligibility. The Company and
Local 611 arbitrated the dispute in May 2002 and on July 24, 2002, the
arbitrator issued a written decision in favor of the Company denying the
grievance.
WESTERN RESOURCES
On November 9, 2000, the Company and Western Resources announced that
both companies' Boards of Directors approved an agreement under which the
Company would acquire the Western Resources electric utility operations in a
tax-free, stock-for-stock transaction. The agreement required that Western
Resources split-off its non-utility businesses to its shareholders prior to
closing.
In July 2001, the KCC issued two orders. The first order declared the
split-off required by the agreement to be unlawful as designed, with or without
a merger. The second order decreased rates for Western Resources, despite a
request for $151 million increase. After rehearing the KCC established the rate
decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on
Reconsideration reaffirming its decision that the split-off as designed in the
agreement was unlawful with or without a merger.
Because of these rulings, the Company announced that it believed the
agreement as originally structured could not be consummated. Efforts to
renegotiate the transaction failed. Western Resources demanded that the Company
file for regulatory approvals of the transaction as designed, despite the fact
that the transaction required the split-off already determined to be unlawful by
the KCC. As a result of the disagreement over the viability of the transaction
as designed, the Company filed suit on October 12, 2001, in New York state
court. On May 10, 2002, the Company filed an Amended Complaint seeking
unspecified damages from Western Resources for numerous breaches of contract
related to the determination that the split-off required by the agreement was
unlawful and required prior approval by the KCC. The Company also seeks
unspecified damages for additional breaches of contract because: Western
Resources failed to provide the Company with the opportunity to review and
comment on information related to the transaction provided by Western Resources
to third parties; Western Resources failed to obtain the Company's consent to
amend existing employee compensation and benefits plans or create new ones; and
Western Resources filed for approval of an alternative debt reduction plan that
represents the abandonment of the split-off required by the agreement. In
addition the Company seeks numerous declarations from the court, including that
the Company was not obligated to perform because conditions regarding
performance were not satisfied; the Company did not breach when it terminated
the agreement; and the rate case order constitutes a material adverse effect
under the terms of the agreement.
On January 7, 2002, the Company notified Western Resources that it had
taken action to terminate the agreement as of that date. The Company identified
numerous breaches of the agreement by Western Resources and the regulatory
rulings in Kansas as reasons for the termination. On January 9, 2002, Western
77
Resources responded that it considered the Company's termination to be
ineffective and the agreement to still be in effect. However, the Company
subsequently received a letter dated May 28, 2002, from counsel for Western
Resources purporting to terminate the agreement and demanding payment of a $25
million termination fee, which the Company declined to pay.
On May 30, 2002, Western Resources filed counterclaims against the
Company in New York state court alleging breach of contract and fraud. Western
Resources alleged that the Company's January 7 letter constituted a withdrawal
or adverse modification of the Company's adoption of the agreement or
recommendation that its shareholders approve the agreement. As a result Western
Resources claims that the Company is liable for a $25 million termination fee
plus costs and expenses (including attorneys fees) incurred in connection with
the litigation. Western Resources also claims that the Company committed fraud
by not timely disclosing to Western Resources its intentions not to proceed with
the transaction and is seeking additional unspecified damages. The Company
believes that the counterclaims filed by Western Resources are without merit and
intends to vigorously defend itself against them. The Company also intends to
vigorously pursue its own complaint.
On July 3, 2002, the Company filed a Motion for Partial Summary Judgment
and for Dismissal of Counterclaims and Defenses.
The Company is unable to predict the ultimate outcome of its litigation
with Western Resources.
California Attorney General Complaint
In March 2002, the California Attorney General filed a complaint at the
FERC against numerous sellers regarding prices for sales into the Cal ISO and
Cal PX and to the California Department of Water Resources ("Cal DWR"). The
Company was among the sellers identified in this complaint and the Company filed
its answer and motion to intervene. In its answer, the Company defended its
pricing and challenged the theory of liability underlying the California
Attorney General's complaint. On May 31, 2002, the FERC entered an order denying
the rate relief requested in the complaint, but directing sellers, including the
Company, to comply with additional reporting requirements with regard to certain
wholesale power transactions. The Company has made required filings under the
May 31 order. The Attorney General has filed a request for rehearing that is
pending at the FERC.
California Antitrust Litigation
Several class action lawsuits have been filed in California state courts
against electric generators and marketers, alleging that the defendants violated
the law by manipulating the market to grossly inflate electricity prices. Named
defendants in these lawsuits include Duke Energy ("Duke") and related entities
along with other named sellers into the California market and numerous other
"unidentified defendants." These lawsuits were consolidated for hearing in state
court in San Diego. On May 3, 2002, the Duke defendants in the foregoing state
court litigation served a cross-claim on the Company. Duke also cross-claimed
against many of the other sellers into California. Duke asked for declaratory
relief and for indemnification for any damages that might ultimately be imposed
on Duke. Several defendants have removed the case to federal court and a motion
is pending to remand the case to state court. The Company has joined with other
cross-defendants in motions to dismiss the cross-claim. The Company cannot
predict the outcome of this matter.
78
Citizen Suit Under the Clean Air Act
By letter dated January 9, 2002, counsel for the Grand Canyon Trust and
Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a
so-called "citizen suit" under the Clean Air Act, alleging that the Company and
co-owners of the SJGS violated the Clean Air Act, and the implementing federal
and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002,
the GCT filed suit in federal district court in New Mexico against the Company
(but not against the other SJGS co-owners). The suit alleges two violations of
the Clean Air Act and related regulations and permits. First GCT argues that the
plant has violated, and is currently in violation of, the federal Prevention of
Significant Deterioration ("PSD") rules, as well as the corresponding provisions
of the New Mexico Administrative Code, at all four units. Second, GCT alleges
that the plant has "regularly violated" the 20% opacity limit contained in
SJGS's operating permit and set forth in federal and state regulations at Units
1, 3 and 4. The lawsuit seeks penalties as well as injunctive and declaratory
relief. The Company filed its answer in federal court on June 6, 2002, denying
the material allegations in the complaint. The parties are presently addressing
with the federal magistrate a discovery schedule. Based on its investigation to
date, the Company firmly believes that the allegations are without merit and
vigorously disputes the allegations. The Company has always and continues to
adhere to high environmental standards as evidenced by its ISO 14000
certification. The Company is, however, unable to predict the ultimate outcome
of the matter.
LANDOWNER ENVIRONMENTAL CLAIMS
In March 2002, a lawsuit was filed in the eleventh judicial district of
the state of New Mexico by a landowner, owning property in the vicinity of SJGS,
against the Company and the owner of the coal mine that supplies coal to the
plant. The lawsuit was served on the defendants on June 11, 2002. The complaint
seeks $20 million in damages, plus pre-judgment interest and punitive damages,
based on allegations related to the alleged discharge of pollutants into an
arroyo near the plant, including damage to the plaintiff's livestock. A jury
trial has been demanded. The Company is vigorously defending this matter, but is
unable to predict the outcome of this matter.
79
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Annual Meeting
The annual meeting of shareholders was held on May 14, 2002. The matters
voted on at the meeting and the results were as follows:
The election of the following nominees to serve as directors as follows:
Votes
Against
Director Votes For Or Withheld
-------- --------- -----------
Term expiring in 2003:
Paul F. Roth 33,847,332 177,248
Terms expiring in 2005:
R. Martin Chavez, Ph.D. 33,548,810 475,770
Joyce A. Godwin 33,856,387 168,193
Manuel T. Pacheco, Ph.D. 33,556,254 468,326
As reported in the Definitive 14A Proxy Statement filed April 10, 2002,
the name of each other director whose term of office as director continues after
the meeting is as follows:
Robert G. Armstrong
Benjamin F. Montoya
Theodore F. Patlovich
Robert M. Price
Jeffry E. Sterba
Subsequent to the annual meeting, Benjamin F. Montoya resigned from the
Board.
On April 19, 2002, the Company announced that it would remove Proposal 2:
Approval of Independent Public Accountants from the agenda for the annual
meeting. Due to the developments regarding Arthur Andersen, LLP ("Andersen"),
the Company's proposed auditor, it was considered likely that the Board of
Directors of PNM Resources, Inc. would replace Andersen during 2002. On June 7,
2002, the Board of Directors dismissed Andersen and selected Deloitte and
Touche, LLP to serve as independent accountants for 2002.
80
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
15.0 Letter Re: Unaudited Interim Financial Information
3.1.1 Restated Articles of Incorporation of PNM, as amended
through May 31, 2002.
3.2.1 Bylaws of PNM with all Amendments to and including
May 31, 2002.
99.1 Chief Executive Officer Certification Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
99.2 Chief Financial Officer Certification Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
b. Reports on Form 8-K:
Report dated and filed May 23, 2002 reporting the Company Responds to FERC
Inquiry: No Inappropriate Trades.
Report dated and filed June 10, 2002 reporting the Company's Dismissal of Arthur
Andersen, LLP as Independent Public Accountants for PNM Resources and its
affiliates.
Report dated and filed June 10, 2002 reporting the Company's Comparative
Operating Statistics for the month of May 2002 and 2001 and the year ended May
30, 2002 and 2001.
Report dated and filed June 18, 2002 reporting the Company's Letters from Arthur
Andersen, LLP to the Securities and Exchange Commission dated June 11, 2002
regarding PNM Resources, Inc. and Public Service Company of New Mexico.
Report dated and filed July 10, 2002 reporting the Company Lowers its 2002
Earnings Estimate.
Report dated and filed July 12, 2002 reporting the Company's Comparative
Operating Statistics for the month of June 2002 and 2001 and the year ended June
30, 2002 and 2001.
Report dated and filed July 17, 2002 reporting the Company Declares Common Stock
Dividend.
Report dated and filed July 18, 2002 reporting the Company Names Two New
Directors.
Report dated and filed July 23, 2002 reporting the Company's Quarter Ended June
30, 2002 Earnings Announcement; Consolidated Statement of Earnings, Consolidated
Balance Sheets, Consolidated Statement of Cash Flows and Comparative Operating
Statistics.
Report dated and filed July 24, 2002 reporting the Company's Announcement to
Employees a Reorganization of its Management Committee.
81
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PNM RESOURCES, INC. AND
PUBLIC SERVICE COMPANY OF NEW MEXICO
---------------------------------------------
(Registrant)
Date: August 14, 2002 /s/ John R. Loyack
---------------------------------------------
John R. Loyack
Vice President
and Chief Accounting Officer
(Officer duly authorized to sign this report)
82